Monitoring and Data Analysis Systems and Methods

ABSTRACT

A transformer monitoring device has one or more voltage sensors and/or one or more current sensors integral with a housing for detecting a voltage of a power cable of a transformer. The transformer monitoring device further has one or more environmental sensors including a smoke sensor, ambient temperature sensor, external transformer temperature sensor, a fire sensor, or a surface and/or ground temperature sensor configured to detect smoke in an area surrounding the transformer and a processor configured to monitor the smoke sensor, the processor configured to transmit an alert if smoke is detected surrounding the transformer.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part and claims priority to U.S.patent application Ser. No. 16/984,552 entitled Systems and Methods forMonitoring Transformers and Performing Actions Based on the Monitoringand filed on Aug. 4, 2020, which is a Divisional of and claims priorityto U.S. patent application Ser. No. 15/701,023 entitled TransformerMonitoring and Data Analysis Systems and Methods and filed on Sep. 11,2017, which is a continuation in part and claims priority to U.S. patentapplication Ser. No. 15/357,766 entitled Transformer Monitoring and DataAnalysis Systems and Methods, filed Nov. 21, 2016, which claims priorityto U.S. patent application Ser. No. 14/231,576 entitled Power MonitoringSystem and Method, filed Mar. 31, 2014, which claims priority to U.S.Provisional Patent Application Ser. No. 61/806,513 entitled PowerMonitoring System and Method, filed Mar. 29, 2013, each of which isincorporated herein by reference in their entirety.

BACKGROUND

Power is generated, transmitted, and distributed to a plurality ofendpoints, such as for example, customer or consumer premises(hereinafter referred to as “consumer premises”). Consumer premises mayinclude multiple-family residences (e.g., apartment buildings,retirement homes), single-family residences, office buildings, eventcomplexes (e.g., coliseums or multi-purpose indoor arenas, hotels,sports complexes), shopping complexes, or any other type of building orarea to which power is delivered.

The power delivered to the consumer premises is typically generated at apower station. A power station is any type of facility that generatespower by converting mechanical power of a generator into electricalpower. Energy to operate the generator may be derived from severaldifferent types of energy sources, including fossil fuels (e.g., coal,oil, natural gas), nuclear, solar, wind, wave, or hydroelectric.Further, the power station typically generates alternating current (AC)power.

The AC power generated at the power station is typically increased (thevoltage is “stepped up”) and transmitted via transmission linestypically to one or more transmission substations. The transmissionsubstations are interconnected with a plurality of distributionsubstations to which the transmission substations transmit the AC power.The distribution substations typically decrease the voltage of the ACpower received (the voltage is “stepped down”) and transmit the reducedvoltage AC power to distribution transformers that are electricallyconnected to a plurality of consumer premises. Thus, the reduced voltageAC power is delivered to a plurality of consumer premises. Such a web ornetwork of interconnected power components, transmission lines, anddistribution lines is oftentimes referred to as a power grid.

Throughout the power grid, measurable power is generated, transmitted,and distributed. In this regard, at midpoints or endpoints throughoutthe grid, measurements of power received and/or distributed may indicateinformation related to the power grid. For example, if power distributedat the endpoints on the grid is considerably less than the powerreceived at, for example, distribution transformers, then there may be asystem issue that is impeding delivery of power or power may be beingdiverted through malice. Such power data collection at any of thedescribed points in the power grid and analysis of such data may furtheraid power suppliers in generating, transmitting, and distributing powerto consumer premises.

Similarly, surrounding conditions (e.g., present, changing, etc.) atand/or nearby one or more distribution transformers may be indicative ofcritical information. In this regard, at midpoints or endpointsthroughout the grid whether at distribution transformers and/orotherwise, measurements of surrounding conditions and/or trendingconditions may indicate information related to the power grid and/or tothe nearby environment (e.g., brush fires, wildfires, tampering,radiation, noxious gases, etc.) thereby warranting alert notificationsto operators and/or authorized third parties regarding the presentand/or impending conditions, danger, disaster, and/or other undesirableoutcomes.

SUMMARY

The present disclosure is a transformer monitoring device for monitoringelectric power grids, and the surroundings. The transformer monitoringdevice comprises one or more voltage sensors and/or one or more currentsensors. Notably, the transformer monitoring device need not containboth voltage and current sensors. In this regard, the transformermonitoring device may contain a voltage sensor and not a current sensoror contain a current sensor and not a voltage sensor.

In one embodiment, the transformer monitoring device may comprise one ormore operational internal sensors or probes to monitor operationalvalues or measure other environmental quantities. These environmentalsensors or probes may be contained within the transformer monitoringdevice, and/or coupled directly to a port in the transformer monitoringdevice, and/or the sensors or probes may be external to the transformermonitoring device and coupled to the transformer monitoring device via acable, or wirelessly for example. The sensors or probes may be sensorsor probes for monitoring vibration, ambient temperature, transformerexterior temperature, humidity, ground and/or surface temperature, thepresence of smoke, the presence of nuclear radiation, the presence ofnoxious gases and/or geo-positioning.

Additionally, the transformer monitoring device may comprise one or morelocal interfaces to connect to other internal sensors, and/or externalsensors or probes located in proximity of the transformer monitoringdevice, e.g., a fault indicator or an external temperature probe. Theinterfaces can be wired, such as electrical or optical, or wireless,e.g., ZigBee or other short range radio interfaces. Note that theexternal environmental sensors or probes may also be sensors or probesfor monitoring vibration, ambient temperature, transformer exteriortemperature, humidity, ground and/or surface temperature, the presenceof smoke, the presence of nuclear radiation, the presence of noxiousgases and/or geo-positioning.

As a mere example, the transformer monitoring device typically resideson the secondary side of a transformer. In such a scenario, a voltageconductor on the primary side of the transformer may become broken awayfrom the transformer. A loose or fallen voltage conductor can causeformidable destruction, including loss to life and limb, downstreamappliance and equipment damage, localized asset fire, and/or a wildfire,for example. In such a scenario, the transformer monitoring devicecomprising a voltage sensor and/or a current sensor, smoke or noxiousgases sensor and one or more temperature sensor(s) may detect associatedvoltage change, and/or smoke, and/or noxious gas(es) or an unwarrantedincrease in temperature. The transformer monitoring device may alsodetect a downstream voltage drop or spike in conjunction with the smokeand the unwarranted increase in ambient, transformer exterior, and/orground, or surface temperature(s). When smoke is detected, anunwarranted increase in temperature is detected, and/or an unexplainablevoltage drop or spike is detected, the transformer monitoring device ofthe present disclosure is configured to notify utility personnel orother third parties designated for emergencies.

Further, the transformer monitoring device comprises at least oneprocessor, and other components, such as memory, configured forcollecting samples measured by the sensors and acting upon the collecteddata. In this regard, the processor is configured to act based uponpreprogrammed logic, e.g., firmware. The processor, based upon thesamples measured, is configured to perform calculations, store data,take actions based on the data values, and calculate results.

Additionally, the transformer monitoring device may comprisenon-volatile memory to store logic for executing the above-describedactions. The non-volatile memory may also compriseprogrammable/re-programmable configuration settings, e.g.,pre-determined threshold values, collected data, automated alerts, andcomputed results.

The transformer monitoring device may also comprise a long distance,two-way communication interface to communicate remotely with a centralcomputing device. In this regard, the logic described hereinabove mayreport information to the remote central computing device, receiveinstructions, and receive new logic, or receive configuration settingsfrom the central computing device.

In another embodiment, the transformer monitoring device comprises alocal user interface. The local user interface may display data and/oraccept local user input.

The present disclosure further describes a central computing device thatis configured to interact with a plurality of remotely locatedtransformer monitoring devices. In this regard, the central computingdevice comprises logic configured to collect data from the transformermonitoring device, interpret data received from the transformermonitoring device, and perform operations based upon the data receivedfrom the transformer monitoring devices. The central computing device isfurther configured to transmit instructions, transmit new logic, ortransmit new configuration data to the transformer monitoring devices.Additionally, the central computing device is configured to performremote diagnostics on the transformer monitoring devices.

The central computing device also provides information to users of thecentral computing device via a graphical user interface (GUI). Further,the central computing device is configured to communicate with users,e.g., utility personnel, via e-mail, text messaging, file sharing, andother messaging.

The central computing device is further configured to interface withthird party systems and applications, e.g., Supervisory Control and DataAcquisition (SCADA) systems, meter data management system, outagenotification systems, and the like. Such communication with thesethird-party systems is effectuated using standard and/or proprietaryprotocols to retrieve and/or send information automatically or upondemand.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure can be better understood with reference to thefollowing drawings. The elements of the drawings are not necessarily toscale relative to each other, emphasis instead being placed upon clearlyillustrating the principles of the disclosure. Furthermore, likereference numerals designate corresponding parts throughout the severalviews.

FIG. 1A is a diagram depicting an exemplary power transmission anddistribution system in accordance with an embodiment of the presentdisclosure.

FIG. 1B is a graph depicting temperature changes measured by amonitoring device of the system of FIG. 1A.

FIG. 1C is a graph depicting humidity changes measured by a monitoringdevice of the system of FIG. 1A.

FIG. 1D is a graph depicting infrared temperatures changes measured by amonitoring device of the system of FIG. 1A.

FIG. 1E is a graph depicting infrared ambient temperature changesmeasured by a monitoring device of the system of FIG. 1A.

FIG. 1F is a graph depicting gas value changes measured by a monitoringdevice of the system of FIG. 1A.

FIG. 1G is a graphical user interface showing a table that comprisescounts from an infrared camera data measured by a monitoring device ofthe system of FIG. 1A.

FIG. 2 is a diagram depicting a transformer and meter power usage datacollection system in accordance with an embodiment of the presentdisclosure.

FIG. 3 is a drawing of a general-purpose transformer monitoring device,such as is depicted by FIG. 2A.

FIG. 4 is a block diagram depicting an exemplary operations computingdevice, such as is depicted in FIG. 2A.

FIG. 5 is a block diagram depicting an exemplary transformer monitoringdevice, such as is depicted in FIG. 2A.

FIG. 6 is a drawing of a transformer can in accordance with anembodiment of the present disclosure.

FIG. 7 is a drawing showing a satellite unit of the transformermonitoring device depicted in FIG. 3 being installed on the transformercan depicted in FIG. 6.

FIG. 8 is a drawing showing the satellite unit of the transformermonitoring device depicted in FIG. 3 installed on the transformer candepicted in FIG. 6.

FIG. 9 is a drawing showing a main unit of the transformer monitoringdevice depicted in FIG. 3 installed on the transformer can depicted inFIG. 6.

FIG. 10 is a drawing showing a main unit of the transformer monitoringdevice depicted in FIG. 8 installed on the transformer can depicted inFIG. 6.

FIG. 11 is a diagram depicting a method of monitoring power inaccordance with the system such as is depicted in FIG. 1 for a wyetransformer configuration.

FIG. 12 is a diagram depicting a method of monitoring power inaccordance with the system such as is depicted in FIG. 1 for a Deltatransformer configuration.

FIG. 13 is a diagram depicting a method of monitoring power inaccordance with the system such as is depicted in FIG. 1 for an OpenDelta transformer configuration.

FIG. 14 depicts a polyphase transformer monitoring (PDTM) device inaccordance with an embodiment of the present disclosure.

FIG. 15A is block diagram depicting an exemplary PDTM device, such as isdepicted in FIG. 14.

FIG. 15B is a block diagram depicting another exemplary PDTM device,such as is depicted in 14.

FIG. 16 is a diagram depicting a method of monitoring power with a PDTMof FIG. 14 in accordance with the system such as is depicted in FIG. 1for a wye transformer configuration.

FIG. 17 is a diagram depicting a method of monitoring power with a PDTMof FIG. 14 in accordance with the system such as is depicted in FIG. 1for a Delta transformer configuration.

FIG. 18 is a diagram depicting a method of monitoring power with a PDTMof FIG. 14 in accordance with the system such as is depicted in FIG. 1for a Delta transformer configuration having a center-tapped leg.

FIG. 19 is a flowchart depicting exemplary architecture andfunctionality of monitoring the power transmission and distributionsystem such as is depicted in FIG. 1 with a PDTM of FIG. 14.

FIG. 20 is a diagram depicting an exemplary system of the presentdisclosure showing transformer monitoring devices wirelesslycommunicating with a computing device.

FIG. 21 is a diagram depicting polyphase distribution transformer devicecoupled to a control box and wirelessly communicating with a computingdevice.

FIG. 22 is a block diagram depicting an exemplary computing device ofFIGS. 20 and 21 in accordance with an embodiment of the presentdisclosure.

FIG. 23 is a diagram depicting another exemplary system wherein thetransformer monitoring device is communicatively coupled to a centralcomputing device and a portable device.

FIG. 24 is a diagram depicting another exemplary system wherein apolyphase distribution transformer device is communicatively coupled toa central computing device and a portable device.

FIG. 25 is a diagram depicting a transformer circuit in accordance withan embodiment of the present disclosure.

FIG. 26 is a diagram depicting multiple transformers coupled to powerlines wherein at least one transformer is coupled to a transformermonitoring device.

FIG. 27 is a block diagram of an exemplary transformer monitoring deviceoperating as a repeater in accordance with an embodiment of the presentdisclosure.

FIG. 28A-28E are depictions of exemplary voltage terminators that may beused on the transformer monitoring devices depicted in FIGS. 23 and 24.

DETAILED DESCRIPTION

FIG. 1A is a block diagram illustrating a power transmission anddistribution system 100 for delivering electrical power to one or moreconsumer premises 106-111. The one or more consumer premises 106-111 maybe business consumer premises, residential consumer premises, or anyother type of consumer premise. A consumer premise is any structure orarea to which power is delivered.

The power transmission and distribution system 100 comprises at leastone transmission network 118, at least one distribution network 119, andthe consumer premises 106-111 (described above) interconnected via aplurality of power lines 101 a-101 j.

In this regard, the power transmission and distribution system 100 is anelectric “grid” for delivering electricity generated by a power station10 to the one or more consumer premises 106-111 via the transmissionnetwork 118 and the distribution network 119.

Note that the power lines 101 a and 101 b are exemplary transmissionlines, while power lines 101 c, 101 d, are exemplary distribution lines.In one embodiment, the transmission lines 101 a and 101 b transmitelectricity at high voltage (110 kV or above) and transmit electricityvia overhead power lines. At distribution transformers, the AC power istransmitted over the distribution lines at lower voltage (e.g., 25 kV orless). Note that in such an embodiment, the power transmission describeduses three-phase alternating current (AC). However, other types of powerand/or power transmission may be used in other embodiments.

The transmission network 118 comprises one or more transmissionsubstation 102 (only one is shown for simplicity). The power station 10is electrically coupled to the transmission substation 102 via the powerlines 101 a, and the transmission substation 102 is electricallyconnected to the distribution network 119 via the power lines 101 b. Asdescribed hereinabove, the power station 10 (transformers not shownlocated at the power station 10) increases the voltage of the powergenerated prior to transmission over the transmission lines 101 a to thetransmission substation 102. Note that three wires are shown making upthe power lines 101 a indicating that the power transmitted to thetransmission substation 102 is three-phase AC power. However, othertypes of power may be transmitted in other embodiments.

In this regard, at the power station 10, electricity is generated, andthe voltage level of the generated electricity is “stepped up,” i.e.,the voltage of the generated power is increased to high voltage (e.g.,110 kV or greater), to decrease the amount of losses that may occurduring transmission of the generated electricity through thetransmission network 118.

Note that the transmission network 118 depicted in FIG. 1 comprises onlytwo sets of transmission lines 101 a and 101 b (three lines each forthree-phase power transmissions as indicated hereinabove) and onetransmission substation 102. The configuration of FIG. 1 is merely anexemplary configuration. The transmission network 118 may compriseadditional transmission substations interconnected via a plurality ofadditional transmission lines. The configuration of the transmissionnetwork 118 may depend upon the distance that the voltage-increasedelectricity may need to travel to reach the desired distribution network119.

The distribution network 119 transmits electricity from the transmissionnetwork 118 to the consumer premises 106-111. In this regard, thedistribution network 119 comprises a distribution substation transformer103 and one or more distribution transformers 104 and 121. Note that theconfiguration shown in FIG. 1 comprising the distribution substationtransformer 103 and two distribution transformers 104 and 121 andshowing the distribution substation transformer 103 physically separatedfrom the two distribution transformers 104 and 121 is an exemplaryconfiguration. Other configurations are possible in other embodiments.

As an example, the distribution substation transformer 103 and thedistribution transformer 104 may be housed or combined in otherconfigurations of the distribution network 119 (as well as distributionsubstation transformer 103 and distribution transformer 121). Inaddition, one or more transformers may be used to condition theelectricity, i.e., transform the voltage of the electricity, to anacceptable voltage level for delivery to the consumer premises 106-111.The distribution substation transformer 103 and the distributiontransformer 104 may “step down,” i.e., decrease the voltage of theelectricity received from the transmission network 118, before thedistribution substation transformer 103 and the distributiontransformers 104, 121 transmit the electricity to its intendeddestinations, e.g., the consumer premises 106-111.

As described hereinabove, in operation the power station 10 iselectrically coupled to the transmission substation 102 via the powerlines 101 a. The power station 10 generates electricity and transmitsthe generated electricity via the power lines 101 a to the transmissionsubstation 102. Prior to transmission, the power station 10 increasesthe voltage of the electricity so that it may be transmitted overgreater distances efficiently without loss that affects the quality ofthe electricity delivered. As further indicated hereinabove, the voltageof the electricity may need to be increased to minimize energy losses asthe electricity is being transmitted on the power lines 101 b. Thetransmission substation 102 forwards the electricity to the distributionsubstation transformer 103 of the distribution network 119.

When the electricity is received, the distribution substationtransformer 103 decreases the voltage of the electricity to a range thatis useable by the distribution transformers 104, 121. Likewise, thedistribution transformers 104, 121 may further decrease the voltage ofthe electricity received to a range that is useable by the respectiveelectrical systems (not shown) of the consumer premises 106-111.

In one embodiment of the present disclosure, the distributiontransformers 104, 121 are electrically coupled to transformer monitoringdevices 244, 243, respectively. The transformer monitoring devices 244,243 of the present disclosure comprises one or more electrical devicesthat measure operational data via one or more electrical interfaces withthe distribution transformers 104, 121. Exemplary operational dataincludes data related to electricity that is being delivered to ortransmitted from the distribution transformers 104, 121, e.g., powermeasurements, energy measurements, voltage measurements, currentmeasurements, etc. The operational data may also include data indicativeof power received from energy sources on the customer premises, e.g.,solar or wind power. In addition, the transformer monitoring devices244, 243 may collect operational data related to the environment inwhich the distribution transformers 104, 121 are situated, e.g.,operating external temperature of the distribution transformers, and/ornearby conditions including ambient temperature, ground/surfacetemperature, the presence of smoke and/or noxious gases, humidity, etc.104, 121.

In accordance with one embodiment of the present disclosure, thetransformer monitoring devices 244, 243 electrically interface withpower lines 101 e-101 j (e.g., a set of three power lines deliveringpower to consumer premises 106-111, if the power is three-phase). Thus,the transformer monitoring devices 244, 243 collects the data, whichrepresents the amount of electricity (i.e., power being used or powerbeing delivered in the case of solar or wind energy) that is beingdelivered to or received from the consumer premises 106-111. In anotherembodiment, the transformer monitoring devices 244, 243 may electricallyinterface with the power lines 101 c-101 d (i.e., the power linesdeliver electricity from the transmission network 118).

Furthermore, each consumer premise 106-111 comprises an electricalsystem (not shown) for delivering electricity received from thedistribution transformers 104, 121 to one or more electrical ports (notshown) of the consumer premise 106-111. Note that the electrical portsmay be internal or external ports.

The electrical system of each consumer premise 106-111 interfaces with acorresponding consumer premise's electrical meter 112-117, respectively.Each electrical meter 112-117 measures the amount of electricityconsumed by or received from the consumer premises' electrical system towhich it is coupled. To charge a customer who is responsible for theconsumer premise, a power company (e.g., a utility company or a meteringcompany) retrieves data indicative of the measurements made by theelectrical meters 112-117 and uses such measurements to determine theconsumer's invoice dollar amount representative of how much electricityhas been consumed at the consumer premise 106-111. Notably, readingstaken from the meters 112-117 reflect the actual amount of powerconsumed by the respective consumer premise electrical system. Thus, inone embodiment of the present disclosure, the meters 112-117 store dataindicative of the power consumed by the consumers.

As described hereinabove, the consumer premises may have solar panels,energy producing wind implements, or any other means of distributedenergy generation systems. In such an embodiment, the alternative energysource may inject energy into the distribution network 119 instead ofconsuming it. In this regard, the meters 112-117 and the transformermonitoring devices 244, 243 may register this reverse energy in caseswhere the energy flow goes the opposite way of consumption, i.e.,injection into the distribution network 119.

During operation, the meters 112-117 may be queried using any number ofmethods to retrieve and store data indicative of the amount of powerbeing consumed by the meter's respective consumer premise electricalsystem or the power being generated at the consumer premise. Utilitypersonnel may physically go to the consumer premises 106-111 and readthe consumer premise's respective meter 112-117. In such a scenario, thepersonnel may enter data indicative of the readings into an electronicsystem, e.g., a hand-held device, a personal computer (PC), or a laptopcomputer. Periodically, the data entered may be transmitted to ananalysis repository (not shown). Additionally, meter data retrieval maybe electronic and automated. For example, the meters 112-117 may becommunicatively coupled to a network (not shown), e.g., a wirelessnetwork, and periodically the meters 112-117 may automatically transmitdata to the repository, described herein with reference to FIG. 2A.

As will be described further herein, meter data (not shown) (i.e., dataindicative of readings taken by the meters 112-117) and transformer data(not shown) (i.e., data indicative of readings taken by the transformermonitoring devices 244, 243) may be stored, compared, and analyzed inorder to determine whether particular events have occurred, for example,whether electricity theft is occurring or has occurred between thedistribution transformers 104, 121 and the consumer premises 106-111 orto determine whether power usage trends and/or power delivery trends(e.g., from solar panels) indicate a need or necessity for more or lesspower supply equipment. With respect to the theft analysis, if theamount of electricity being received at the distribution transformers104, 121 is much greater than the cumulative (or aggregate) total of theelectricity that is being delivered to the consumer premises 106-117,then there is a possibility that an offender may be stealing electricityfrom the utility providing the power.

Another cause for a difference between the power or energy measured bythe meters 112-117 and the energy consumption measured at thedistribution transformers 104, 121 is that there may be an incorrectmapping or association of the distribution transformers 104, 121 and themeters 112-117. In this regard, more or fewer meters 112-117 may beincorrectly mapped to the distribution transformers 104, 121, whichwould cause the mismatch between the cumulative power measured by themeters and the power consumption measure by the transformer monitoringdevices 244, 243.

In another embodiment, power usage data is compiled over time. Thecompilation of the power usage data may be used in many ways. Forexample, it may be predetermined that a power usage signature, e.g.,power usage which can be illustrated as a graphed footprint over aperiod, indicates nefarious activity. Such is described further herein.

In one embodiment, the power transmission and distribution system 100further comprises one or more monitoring devices (MD) 290-293. MD 290 iscoupled to one or more of the power lines 101 c and MD 292 is coupled toone or more of the power lines 101 d. In addition, MD 291 is coupled topower transmission tower 140, and MD 293 is coupled to powertransmission tower 141. Note that in one embodiment, the MDs 290-293 maycollect voltage and current information; however, the MDs 290-293 do notnecessarily have to comprise this capability.

In this regard, the MDs 290-293 collect environmental data surroundingthe MDs 290-293. Each monitoring device comprises environmental sensorsor probes for collecting data indicative of ambient temperature, MDexterior temperature, humidity, ground and/or surface temperature,vibration, smoke, nuclear radiation, noxious gases, and geo-positioning.In such a scenario, if one of the monitored characteristics indicates aproblem the MD 290-293 is configured to alert utility personnel oranother individual in charge of emergency situations.

Each MD 290-293 may comprise a smoke sensor, an ambient temperaturesensor, and a ground and/or surface temperature sensor. In such ascenario, the MD 290-293 is configured to detect fire in proximity tothe MD 290-293. The smoke sensor detects the smoke from a fire. Theambient temperature sensor detects the temperature surrounding the MD290-293, and the ground and/or surface temperature sensor detects theactual fire temperature and/or detects the ground or surfacetemperature. Taken together, data indicative of the smoke, the ambienttemperature, the actual fire, and ground and/or surface temperature maybe compared to normalized data, and if the data indicative of the smoke,the ambient temperature, the actual fire temperature, and/or the groundand/or surface temperature exceeds a particular value, a fire isindicated. When a fire is indicated, the MD 290-293 reports the firecondition to a computing device of a utility company, to a handhelddevice of personnel, and/or to a third-party computing device.

FIG. 1B is a graph 180 depicting temperature changes measured by a MDs290-293 of the system of FIG. 1A. In this regard, graph line 181 depictschanges in temperature over time. If the MDs 290-2993 measures atemperature that exceeds a threshold value, this may indicate a fire.Taken with other data, the MDs 290-293 may alert personnel at a utilitycompany of a potential fire.

FIG. 1C is a graph 182 depicting humidity changes measured by the MDs290-293 of the system of FIG. 1A. In this regard, graph line 183 depictschanges in humidity over time. If the MDs 290-2993 measures a humiditythat falls below a threshold value, this may indicate a fire. Taken withother data, the MDs 290-293 may alert personnel at a utility company ofa potential fire.

FIG. 1D is a graph 184 depicting infrared temperatures changes measuredby MDs 290-293 of the system of FIG. 1A. In this regard, graph line 185depicts changes in infrared temperature over time. If the MDs 290-2993measures a temperature that exceeds a threshold value, this may indicatea fire. Taken with other data, the MDs 290-293 may alert personnel at autility company of a potential fire.

FIG. 1E is a graph 186 depicting infrared ambient temperature changesmeasured by MDs 290-293 of the system of FIG. 1A. In this regard, graphline 187 depicts changes in infrared ambient temperature over time. Ifthe MDs 290-2993 measures an ambient temperature that exceeds athreshold value, this may indicate a fire. Taken with other data, theMDs 290-293 may alert personnel at a utility company of a potentialfire.

FIG. 1F is a graph 188 depicting gas value changes measured by MDs290-293 of the system of FIG. 1A. In this regard, graph line 189 depictschanges in gas presence over time. If the MDs 290-2993 measures gas thatexceeds a threshold value, this may indicate a fire. For example, manywildfires produce the predominant toxic gas, carbon monoxide. Taken withother data, the MDs 290-293 may alert personnel at a utility company ofa potential fire.

FIG. 1G is a graphical user interface (GU) 190 showing a table thatcomprises data indicative of outputs of an infrared camera measured byMDs 290-293 of the system of FIG. 1A. In this regard, the infraredcamera measures intensities of its surroundings and displays dataindicative of the intensities in each box. If the counts exceed athreshold value, this may indicate a fire. Taken with other data, theMDs 290-293 may alert personnel at a utility company of a potentialfire.

In one embodiment, the MDs 290-293 comprise a voltage sensor. In such ascenario the MDs 290-293 may detect when an extreme voltage drop occurs.The extreme voltage drop may be from, for example, conductors decouplingfrom the grid and falling to the ground. On the ground, the conductorsare a fire hazard. Thus, the MDs 290-293 may alert personnel at autility company of a situation that may lead to a fire.

Further, the MDs 290-293 may detect extremely high voltages. In such ascenario, the MDs 290-293 may detect the extremely high voltages, whichmay be a fire hazard. Thus, the MDs 290-293 may alert personnel at autility company of a situation that may lead to a fire.

FIG. 2 depicts a transformer data collection system 105 in accordancewith an embodiment of the present disclosure and a plurality of meterdata collection devices 986-991. The transformer data collection system105 comprises the one or more transformer monitoring devices 243, 244.Note that only two transformer monitoring devices 243, 244 are shown inFIG. 2A, but additional transformer monitoring devices may be used inother embodiments, including one or a plurality transformer monitoringdevices for each distribution transformer 104, 121 (FIG. 1) beingmonitored, which is described in more detail herein.

Notably, in one embodiment of the present disclosure, the transformermonitoring devices 243, 244 are coupled to secondary side of thedistribution transformers, 104, 121, respectively. Thus, measurementstaken by the transformer monitoring devices 243, 244 are taken, ineffect, at the distribution transformers 104, 121 between thedistribution transformers 243, 244 and the consumer premises 106-111(FIG. 1).

Additionally, the transformer monitoring devices 243, 244, the meterdata collection devices 986-991, and an operations computing device 287may communicate via a network 280. The network 280 may be any type ofnetwork over which devices may transmit data, including, but not limitedto, a wireless network, a wide area network, a large area network, orany type of network known in the art or future-developed.

In another embodiment, the meter data 935-940 and the transformer data240, 241, may be transmitted via a direct connection to the operationscomputing device 287 or manually transferred to the operations computingdevice 287. As an example, the meter data collection devices 986-991 maybe directly connected to the operations computing device 287 via adirection connection, such as for example a T-carrier 1 (T1) line. Also,the meter data 935-940 may be collected on by a portable electronicdevice (not shown) that is then connected to the operations computingdevice 287 for transfer of the meter data 936-940 collected to theoperations computing device 287. In addition, meter data 935-940 may becollected manually through visual inspection by utility personnel andprovided to the operations computing device 287 in a format, e.g., commaseparated values (CSV).

Note that in other embodiments of the present disclosure, the meter datacollection devices 986-991 may be the meters 112-117 (FIG. 1)themselves, and the meters 112-117 may be equipped with networkcommunication equipment (not shown) and logic (not shown) configured toretrieve readings, store readings, and transmit readings taken by themeters 112-117 to the operations computing device 287.

The transformer monitoring devices 243, 244 are electrically coupled tothe distribution transformers 104, 121, respectively. In one embodiment,the devices 243, 244 are electrically coupled to the distributiontransformers 104, 121, respectively, on a secondary side of thedistribution transformers 104, 121.

The transformer monitoring devices 243, 244 each comprise one or moresensors (not shown) that interface with one or more power lines (notshown) connecting the distribution transformers 104, 121 to the consumerpremises 106-111 (FIG. 1). Thus, the one or more sensors of thetransformer monitoring devices 243, 244 senses electricalcharacteristics, e.g., voltage and/or current, present in the powerlines as power is delivered to the consumer premises 106-111 through thepower lines 101 e-101 j. Periodically, the transformer monitoringdevices 243, 244 sense such electrical characteristics, translate thesensed characteristics into transformer data 240, 241 indicative ofelectrical characteristics, such as, for example power, and transmittransformer data 240, 241 to the operations computing device 287 via thenetwork 280. Upon receipt, the operations computing device 287 storesthe transformer data 240, 241 received.

Note that there is a transformer monitoring device depicted for eachdistribution transformer in the exemplary system, i.e., transformermonitoring device 243 for monitoring transformer 121 (FIG. 1) andtransformer monitoring device 244 for monitoring transformer 104 (FIG.1). There may be additional transformer monitoring devices formonitoring additional transformers in other embodiments.

The meter data collection devices 986-991 are communicatively coupled tothe network 280. During operation, each meter data collection device986-991 senses electrical characteristics of the electricity, e.g.,voltage and/or current, that is transmitted by the distributiontransformers 104, 121. Each meter data collection device 986-991translates the sensed characteristics into meter data 935-940,respectively. The meter data 935-940 is data indicative of electricalcharacteristics, such as, for example power consumed in addition tospecific voltage and/or current measurements. Further, each meter datacollection device 986-991 transmits the meter data 935-940,respectively, to the operations computing device 287 via the network280. Upon receipt, the operations computing device 287 stores the meterdata 935-940 received from the meter data collection devices 986-991indexed (or keyed) with a unique identifier corresponding to the meterdata collection device 986-991 that transmits the meter data 935-940.

In one embodiment, each meter data collection device 986-991 maycomprise Automatic Meter Reading (AMR) technology, i.e., logic (notshown) and/or hardware, or Automatic Metering Infrastructure (AMI)technology, e.g., logic (not shown) and/or hardware for collecting andtransmitting data to a central repository, (or more centralrepositories) e.g., the operations computing device 287.

In such an embodiment, the AMR technology and/or AMI technology of eachdevice 986-991 collects data indicative of electricity consumption byits respective consumer premise power system and various otherdiagnostics information. The meter logic of each meter data collectiondevice 986-991 transmits the data to the operations computing device 287via the network 280, as described hereinabove. Note that the AMRtechnology implementation may include hardware such as, for example,handheld devices, mobile devices, and network devices based on telephonyplatforms (wired and wireless), radio frequency (RF), or power linecommunications (PLC).

Upon receipt, the operations computing device 287 compares aggregatemeter data of those meters corresponding to a single transformer withthe transformer data 240, 241 received from the transformer monitoringdevice 244, 243 that provided the transformer data 240, 241.

Thus, assume that meter data collection devices 986-988 are coupled tometers 112-114 (FIG. 1) and transmit meter data 935-937, respectively,and distribution transformer 104 is coupled to transformer monitoringdevice 243. In such a scenario, the meters 112-114 meter electricityprovided by the distribution transformer 104 and consumed by theelectrical system of the respective consumer premise 106-108 (FIG. 1).Therefore, the operations computing device 287 aggregates (e.g., sums)data contained in meter data 935-937 (e.g., power usage recorded by eachmeter 112-114) and compares the aggregate with the transformer data 240provided by transformer monitoring device 243.

If the operations computing device 287 determines that the quantity ofpower that is being delivered to the consumer premises 106-108 connectedto the distribution transformer 104 is substantially less than thequantity of power that is being transmitted to the distributiontransformer 104, the operations computing device 287 may determine thatpower (or electricity) theft or transformer to meter mismatch isoccurring.

Note that transformers 104, 121 (FIG. 1) are physically connected tocustomers premises 106-108 and 109-111 to deliver energy. In a typicalsystem, a transformer is configured to deliver energy to a plurality ofcustomers. As an example, the transformer is configured to provideenergy to N customers, customers A, B, C, D, and E. The utility has alogical representation of the connections, e.g., meters to transformerassociation, in a geographic information system (GIS) mapping system.However, the representation does not often match the physical connectionin the field. As an example, after a few years, a crew performsmaintenance on the transformer and disconnects customer E from thetransformer and connects the customer to a different transformer. Ifutility crews in the field fail to report the change to the utility, theGIS mapping of the transformers to meters may no longer be accurate.

In such a scenario, the transformer monitoring devices 243, 244 areconfigured to collect data indicative of power registered by thetransformer monitoring device 243 or 244. In one embodiment, the dataindicative of the collected power information may be compared to a sumof the individual power registered by the respective meters 112-117 bythe transformer monitoring device. In this regard, the metering data maybe transmitted to the transformer monitoring devices 243, 244 via thenetwork 280. In another embodiment, the transformer monitoring devicesmay transmit the collected power information to the operations computingdevice 287, and the operations computing device 287 may compare thecollected power information to meter data 935-940 collected via thenetwork 280.

If the collected power data does not match the sum of the individualmeters supposedly connected to the transformer being monitored by thetransformer monitoring device 243 or 244, the mismatch may indicateseveral scenarios. The mismatch may indicate that there is ongoing theftof electricity. Additionally, the mismatch may be due to streetlights ortraffic lights or an error in mapping of transformers to meters. Theactual cause of the apparent mismatch may then be investigated byutility personnel. In this regard, the operations computing device 287may initiate a visual or audible warning that there is a mismatch in thepower data collected and the meter data 935-940 and send an alert,including location information, to utility personnel. In one embodiment,the operations computing device 287 identifies, stores, and analyzesmeter data 935-940 based on a unique identifier associated with themeter 112-117 to which the meter data collection devices 986-991 arecoupled. Further, the operations computing device 287 identifies,stores, and analyzes transformer data 240, 241 based on a uniqueidentifier associated with the distribution transformers 104, 121 thattransmitted the transformer data 240, 241 to the operations computingdevice 287.

Thus, in one embodiment, prior to transmitting data to the operationscomputing device 287, both the meter data collection devices 986-991 andthe transformer monitoring devices 243, 244 are populated internallywith a unique identifier (i.e., a unique identifier identifying themeter data collection device 986-991 and a unique identifier identifyingthe transformer monitoring device 243, 244). Further, each meter datacollection device 986-991 may be populated with the unique identifier ofthe transformer 104, 121 to which the meter data collection device986-991 is coupled.

In such an embodiment, when the meter data collection device 986-991transmits the meter data 935-940 to the operations computing device 287,the operations computing device 287 can determine which distributiontransformer 104 or 121 services the consumer premises 106-111. As anexample, during setup of a portion of the grid (i.e., power transmissionand distribution system 100 (FIG. 1)) that comprises the distributiontransformers 104, 121 and the meters 112-117, the operations computingdevice 287 may receive set up data from the distribution transformers104, 121 and the meter data collection devices 986-991 identifying thedevice from which it was sent and a unique identifier identifying thecomponent to which the meter data collection device 986-990 isconnected.

FIG. 3 depicts an embodiment of a general-purpose transformer monitoringdevice 1000 that may be used as the transformer monitoring devices 243,244 depicted in FIG. 2A and/or line monitoring devices 270-272 (FIG.2B). The transformer monitoring device 1000 may be installed onconductor cables (not shown) and used to collect data indicative ofvoltage and/or current from the conductor cables to which it is coupled.Note that the transformer monitoring device 1000 may also compriseenvironmental sensors or probes for collecting data indicative ofambient temperature, transformer exterior temperature, humidity, groundand/or surface temperature, vibration, smoke, nuclear radiation, noxiousgases, and geo-positioning. In such a scenario, if one of the monitoredcharacteristics indicates a problem the transformer monitoring device1000 is configured to notify utility personnel or another individual incharge of emergency situations.

In particular, the transformer monitoring device 1000 may comprise asmoke sensor, and ambient temperature sensor, and a ground and/orsurface temperature sensor. In such a scenario, the transformermonitoring device 1000 can detect fire in proximity to the transformerto which the transformer monitoring device 1000 is coupled. The smokesensor detects the smoke from a fire. The ambient temperature sensordetects the temperature surrounding the transformer monitoring device1000, and the ground and/or surface temperature sensor detects theactual fire temperature and/or detects the ground or surfacetemperature. Taken together, data indicative of the smoke, the ambienttemperature, and the actual fire, ground and/or surface temperature maybe compared to normalized data, and if the data indicative of the smoke,the ambient temperature, the actual fire temperature, and/or the groundand/or surface temperature exceeds a particular value, a fire isindicated. When a fire is indicated, the transformer monitoring device1000 reports the fire condition to a computing device of a utilitycompany, to a handheld device of personnel, and/or to a third-partycomputing device.

The general-purpose transformer monitoring device 1000 comprises asatellite unit 1021 that is electrically coupled to a main unit 1001. Inone embodiment, the satellite unit 1021 is coupled via a cable 1011.However, the satellite unit 1021 may be coupled other ways in otherembodiments, e.g., wirelessly. The general-purpose transformermonitoring device 1000 may be used in many different methods to collectvoltage and/or current data (i.e., transformer data 240, 241 (FIG. 2A)from the distribution transformers 104, 121 (FIG. 1) and from the powerlines 101 b-101 j (FIG. 1).

To collect voltage and/or current data, the satellite unit 1021 and/orthe main unit 1001 is installed around a conductor cable or connectorsof conductor cables (also known as a “bushing”). The satellite unit 1021of the general-purpose transformer monitoring device 1000 comprises twoarched sections 1088 and 1089 that are hingedly coupled at hinge 1040.When installed and in a closed position (as shown in FIG. 3), thesections 1088 and 1089 connect via a latch 1006 and the conductor cableruns through an opening 1019 formed by coupling the sections 1088 and1089.

The satellite unit 1021 further comprises a sensing unit housing 1005that houses a current detection device (not shown) for sensing currentflowing through the conductor cable around which the sections 1088 and1089 are installed. In one embodiment, the current detection device maycomprise an implementation of one or more coreless current sensor asdescribed in U.S. Pat. No. 7,940,039, which is incorporated herein byreference.

The main unit 1001 comprises arched sections 1016 and 1017 that arehingedly coupled at hinge 1015. When installed and in a closed position(as shown in FIG. 3), the sections 1016 and 1017 connect via a latch1002 and a conductor cable runs through an opening 1020 formed bycoupling the sections 1016 and 1017.

The main unit 1001 comprises a sensing unit housing section 1018 thathouses a current detection device (not shown) for sensing currentflowing through the conductor cable around which the sections 1016 and1017 are installed. As described hereinabove with respect to thesatellite unit 1021, the current detection device may comprise animplementation of one or more Ragowski coils as described in U.S. Pat.No. 7,940,039, which is incorporated herein by reference.

Unlike the satellite unit 1021, the main unit section 1001 comprises anextended boxlike housing section 1012. Within the housing section 1012resides one or more printed circuit boards (PCB) (not shown),semiconductor chips (not shown), and/or other electronics (not shown)for performing operations related to the general-purpose transformermonitoring device 1000. In one embodiment, the housing section 1012 is asubstantially rectangular housing; however, differently sized, anddifferently shaped housings may be used in other embodiments.

Additionally, the main unit 1001 further comprises one or more cables1004, 1007. The cables 1004, 1007 may be coupled to a conductor cable orcorresponding bus bars (not shown) and ground or reference voltageconductor (not shown), respectively, for the corresponding conductorcable, which will be described further herein.

In one embodiment, the satellite unit 1021 and the cables 1004 and 1007are not permanently mounted to the main unit 1001 but may be mounted tothe main unit 1001 via external weatherproof connectors. In such ascenario, the satellite unit 1021 may be decoupled from the main unit1001 and replaced, for example if the satellite unit 1021 is not workingproperly. Further, the cables 1004 and 1007 may also be decoupled andreplaced, for example if the cables 1004 and 1007 are not workingproperly.

Note that methods in accordance with an embodiment of the presentdisclosure use the described transformer monitoring device 1000 forcollecting current and/or voltage data. Further note that thetransformer monitoring device 1000 described is portable and easilyconnected and/or coupled to an electrical conductor and/or transformerposts. Due to the noninvasive method of installing the satellite unitand main unit around a conductor and connecting the leads 1004, 1007 toconnection points, an operator (or utility personnel) need notde-energize a transformer 104, 121 (FIG. 1) for connection or couplingthereto. Further, no piercing (or other invasive technique) of theelectrical line is needed during deployment to the power grid. Thus, thetransformer monitoring device 1000 is easy to install. Thus, deploymentto the power grid is easy to effectuate.

During operation, the satellite unit 1021 and/or the main unit 1001collects data indicative of current through a conductor cable. Thesatellite unit 1021 transmits its collected data via the cable 1011 tothe main unit 1001. Additionally, the cables 1004, 1007 may be used tocollect data indicative of voltage corresponding to a conductor cableabout which the satellite unit is installed. The data indicative of thecurrent and voltage sensed corresponding to the conductor may be used tocalculate power usage.

As indicated hereinabove, there are many different methods that may beemployed using the general-purpose transformer monitoring device 1000 tocollect current and/or voltage data and calculate power usage.

In one embodiment, the general-purpose transformer monitoring device1000 may be used to collect voltage and current data from a three-phasesystem (if multiple general purpose transformer monitoring devices 100are used) or a single-phase system.

The single-phase system has two conductor cables and a neutral cable.For example, electricity supplied to a typical home in the United Stateshas two conductor cables (or hot cables) and a neutral cable. Note thatthe voltage across the conductor cables in such an example is 240 Volts(the total voltage supplied) and the voltage across one of the conductorcables and the neutral is 120 Volts. Such an example is typically viewedas a single-phase system.

In a three-phase system, there are typically three conductor cables anda neutral cable (sometimes there may not be a neutral cable). In onesystem, voltage measured in each conductor cable is 120° out of phasefrom the voltage in the other two conductor cables. Multiple generalpurpose transformer monitoring devices 1000 can obtain current readingsfrom each conductor cable and voltage readings between each of theconductor cables and the neutral (or obtain voltage readings betweeneach of the conductor cables). Such readings may then be used tocalculate power usage.

Note that the main unit 1001 of the general-purpose transformermonitoring device 1000 further comprises one or more light emittingdiodes (LEDs) 1003. The LEDs may be used by logic (not shown butreferred to herein with reference to FIG. 4 as analytic logic 308) toindicate status, operations, or other functions performed by thegeneral-purpose transformer monitoring device 1000.

FIG. 4 depicts an exemplary embodiment of the operations computingdevice 287 depicted in FIG. 2A. As shown by FIG. 4, the operationscomputing device 287 comprises analytic logic 308, meter data 390,transformer data 391, line data 392, and configuration data 312 allstored in memory 300.

The analytics logic 308 generally controls the functionality of theoperations computing device 287, as will be described in more detailhereafter. It should be noted that the analytics logic 308 can beimplemented in software, hardware, firmware, or any combination thereof.In an exemplary embodiment illustrated in FIG. 4, the analytics logic308 is implemented in software and stored in memory 300.

Note that the analytics logic 308, when implemented in software, can bestored and transported on any computer-readable medium for use by or inconnection with an instruction execution apparatus that can fetch andexecute instructions. In the context of this document, a“computer-readable medium” can be any means that can contain or store acomputer program for use by or in connection with an instructionexecution apparatus.

The exemplary embodiment of the operations computing device 287 depictedby FIG. 4 comprises at least one conventional processing element 302,such as a digital signal processor (DSP) or a central processing unit(CPU), that communicates to and drives the other elements within theoperations computing device 287 via a local interface 301, which caninclude at least one bus. Further, the processing element 302 isconfigured to execute instructions of software, such as the analyticslogic 308.

An input interface 303, for example, a keyboard, keypad, or mouse, canbe used to input data by a user of the operations computing device 287.An output interface 304, for example, a printer or display screen (e.g.,a liquid crystal display (LCD)), can be used to output data to the user.In addition, a network interface 305, such as a modem, enables theoperations computing device 287 to communicate via the network 280 (FIG.2A) to other devices in communication with the network 280.

As indicated hereinabove, the meter data 390, the transformer data 391,the line data 392, and the configuration data 312 are stored in memory300. The meter data 390 is data indicative of power usage measurementsand/or other electrical characteristics obtained from each of the meters112-117 (FIG. 1). In this regard, the meter data 390 is an aggregaterepresentation of the meter data 935-940 (FIG. 2A) received from themeter data collection devices 986-991 (FIG. 2A).

In one embodiment, the analytics logic 308 receives the meter data935-940 and stores the meter data 935-940 (as meter data 390) such thatthe meter data 935-940 may be retrieved based upon the transformer 104or 121 (FIG. 1) to which the meter data's corresponding meter 112-117 iscoupled. Note that meter data 390 is dynamic and is collectedperiodically by the meter data collection devices 986-991 from themeters 112-117. For example, the meter data 390 may include, but is notlimited to, data indicative of current measurements, voltagemeasurements, and/or power calculations over a period per meter 112-117and/or per transformer 104 or 121. The analytic logic 308 may use thecollected meter data 390 to determine whether the amount of electricitysupplied by the corresponding transformer 104 or 121 is substantiallyequal to the electricity that is received at the consumer premises106-111.

In one embodiment, each entry of the meter data 935-940 in the meterdata 390 is associated with an identifier (not shown) identifying themeter 112-117 (FIG. 1) from which the meter data 935-940 is collected.Such identifier may be randomly generated at the meter 112-117 via logic(not shown) executed on the meter 112-117.

In such a scenario, data indicative of the identifier generated by thelogic at the meter 112-117 may be communicated, or otherwisetransmitted, to the transformer monitoring device 243 or 244 to whichthe meter is coupled. Thus, when the transformer monitoring devices 243,244 transmit transformer data 240, 241 (FIG. 2), each transformermonitoring device 243, 244 can also transmit its unique meter identifier(and/or the unique identifier of the meter that sent the transformermonitoring device 243, 244 the meter data). Upon receipt, the analyticslogic 308 may store the received transformer data 240, 241 (astransformer data 391) and the unique identifier of the transformermonitoring device 243, 244 and/or the meter unique identifier such thatthe transformer data 391 may be searched on the unique identifiers whenperforming calculations. In addition, the analytics logic 308 may storethe unique identifiers of the transformer monitoring devices 243, 244corresponding to the unique identifiers of the meters 112-117 from whichthe corresponding transformer monitoring devices 243, 244 receive meterdata. Thus, the analytics logic 308 can use the configuration data 312when performing operations, such as aggregating meter data entries inmeter data 390 to compare to transformer data 391.

The transformer data 391 is data indicative of aggregated power usagemeasurements obtained from the distribution transformers 104, 121. Suchdata is dynamic and is collected periodically. Note that the transformerdata 240, 241 comprises data indicative of current measurements, voltagemeasurements, and/or power calculations over a period that indicates theamount of aggregate power provided to the consumer premises 106-111.Notably, the transformer data 391 comprises data indicative of theaggregate power that is being sent to a “group,” i.e., two or moreconsumer premises being monitored by the transformer monitoring devices243, 244, although the transformer data 391 can comprise power data thatis being sent to only one consumer premises being monitored by thetransformer monitoring device.

In one embodiment, during setup of a distribution network 119 (FIG. 1),the analytic logic 308 may receive data identifying the uniqueidentifier for one or more transformers 104, 121. In addition, when atransformer monitoring device 243, 244 is installed and electricallycoupled to one or more transformers 104, 121, data indicative of theunique identifier of the transformers 104, 121 may be provided to themeters 112-117 and/or to the operations computing device 287, asdescribed hereinabove. The operations computing device 287 may store theunique identifiers (i.e., the unique identifier for the transformers) inconfiguration data 312 such that each meter 112-117 is correlated inmemory with a unique identifier identifying the distribution transformerfrom which the consumer premises 106-111 associated with the meter112-117 receives power.

The line data 273-275 is data indicative of power usage measurementsobtained from the line data collection system 290 along transmissionlines 101 b-101 d in the system 100. Such data is dynamic and iscollected periodically. Note that the line data 273-274 comprises dataindicative of current measurements, voltage measurements, and/or powercalculations over a period of time that indicates the amount ofaggregate power provided to the distribution substation transformer 103and the distribution transformers 104, 121. Notably, the line data 392comprises data indicative of the aggregate power that is being sent to a“group,” i.e., one or more distribution substation transformers 103.

During operation, the analytic logic 308 receives meter data 935-940 viathe network interface 305 from the network 280 (FIG. 2) and stores themeter data 935-940 as meter data 390 in memory 300. The meter data 390is stored such that it may be retrieved corresponding to thedistribution transformer 104, 121 supplying the consumer premise 106-111to which the meter data corresponds. Note there are various methods thatmay be employed for storing such data including using uniqueidentifiers, as described hereinabove, or configuration data 312, alsodescribed hereinabove.

The analytic logic 308 may perform a variety of functions to furtheranalyze the power transmission and distribution system 100 (FIG. 1). Asan example, the analytic logic 308 may use the collected transformerdata 391, line data 392, and/or meter data 390 to determine whetherelectricity theft is occurring along the transmission lines 101 a, 101 bor the distribution lines 101 c-101 j. Additionally, the collected datamay be used to determine a mismatch between the number of meterscorresponding to a transformer.

The analytic logic 308 may compare the aggregate power consumed by thegroup of consumer premises (e.g., consumer premises 106-108 or 109-111)and compare the calculated aggregate with the actual power supplied bythe corresponding distribution transformer 104 or 121. In addition, theanalytic logic 308 may compare the power transmitted to the distributionsubstation transformer 103 and the aggregate power received by thedistribution transformers 104, 121, or the analytic logic 308 maycompare the power transmitted to the transmission substation 102 and theaggregate power received by one or more distribution substationtransformers 103.

If comparisons indicate that electricity theft is occurring anywhere inthe power and distribution system 100 (FIG. 1), the analytics logic 308may notify a user of the operations computing device 287 that there maybe a problem. In addition, the analytics logic 308 can pinpoint alocation in the power transmission and distribution system 100 wheretheft may be occurring or where there may be a mismatch betweentransformers and meters. The analytic logic 308 may have a visual oraudible alert to the user, which can include a map of the system 100 anda visual identifier locating the problem.

The analytics logic 308 may perform a variety of operations and analysisbased upon the data received. As an example, the analytic logic 308 mayperform a system capacity contribution analysis. In this regard, theanalytic logic 308 may determine when one or more of the consumerpremises 106-111 have coincident peak power usage (and/or requirements).The analytics logic 308 determines, based upon this data, prioritiesassociated with the plurality of consumer premises 106-111, e.g. whatconsumer premises requires a peak load and at what time. Loads requiredby the consumer premises 106-111 may necessarily affect system capacitycharges; thus, the priority may be used to determine which consumerpremises 106-111 may benefit from demand management.

Additionally, the analytic logic 308 may use the meter data 390 (FIG.4), the transformer data 391, the line data 392, and the configurationdata 312 (collectively referred to as “operations computing devicedata”) to determine asset loading. For example, analyses may beperformed for substation and feeder loading, transformer loading, feedersection loading, line section loading, and cable loading. Also, theoperations computing device 287 may be used to produce detailed voltagecalculations and analysis of the system 100 and/or technical losscalculations for the components of the system 100, and to comparevoltages experienced at each distribution transformer with thedistribution transformer manufacturer minimum/maximum voltage ratingsand identify such distribution transformer(s) which are operatingoutside of the manufacturer's suggested voltages range thereby helpingto isolate power sag (a decrease in power) and power swell (an increasein power) instances, and identify distribution transformer sizing andlongevity information.

In one embodiment, a utility company may install load control devices(not shown). In such an embodiment, the analytics logic 308 may use theoperations computing device 287 to identify one or more locations ofload control devices.

FIG. 5 depicts an exemplary embodiment of the transformer monitoringdevice 1000 depicted in FIG. 3. As shown by FIG. 5, the transformermonitoring device 1000 comprises control logic 2003, voltage data 2001,current data 2002, power data 2020, event data 2060, and configurationdata 2061 stored in memory 2000.

The control logic 2003 controls the functionality of the operationstransformer monitoring device 1000. The control logic 2003 can beimplemented in software, hardware, firmware, or any combination thereof.In an exemplary embodiment illustrated in FIG. 5, the control logic 2003is implemented in software and stored in memory 2000.

Note that the control logic 2003, when implemented in software, can bestored and transported on any computer-readable medium for use by or inconnection with an instruction execution apparatus that can fetch andexecute instructions. In the context of this document, a“computer-readable medium” can be any means that can contain or store acomputer program for use by or in connection with an instructionexecution apparatus.

The exemplary embodiment of the transformer monitoring device 1000depicted by FIG. 5 comprises at least one conventional processingelement 2004, such as a digital signal processor (DSP) or a centralprocessing unit (CPU), that communicates to and drives the otherelements within the transformer monitoring device 1000 via a localinterface 2005, which can include at least one bus. Further, theprocessing element 2004 is configured to execute instructions ofsoftware, such as the control logic 2003.

An input interface 2006, for example, a keyboard, keypad, or mouse, canbe used to input data from a user of the transformer monitoring device1000, and an output interface 2007, for example, a printer or displayscreen (e.g., a liquid crystal display (LCD)), can be used to outputdata to the user. In addition, a network interface 2008, such as a modemor wireless transceiver, enables the transformer monitoring device 1000to communicate with the network 280 (FIG. 2A).

In one embodiment, the transformer monitoring device 1000 furthercomprises a communication interface 2050. The communication interface2050 is any type of interface that when accessed enables power data2020, voltage data 2001, current data 2002, or any other data collectedor calculated by the transformer monitoring device 100 to becommunicated to another system or device. As an example, thecommunication interface may be a serial bus interface that enables adevice that communicates serially to retrieve the identified data fromthe transformer monitoring device 1000. As another example, thecommunication interface 2050 may be a universal serial bus (USB) thatenables a device configured for USB communication to retrieve theidentified data from the transformer monitoring device 1000. Othercommunication interfaces 2050 may use other methods and/or devices forcommunication including radio frequency (RF) communication, cellularcommunication, power line communication, wireless fidelity (Wi-Fi) oroptical communications.

The transformer monitoring device 1000 further comprises one or morevoltage data collection devices 2009 and one or more current datacollection devices 2010. With respect to the transformer monitoringdevice 1000 depicted in FIG. 3, the transformer monitoring device 1000comprises the voltage data collection device 2009 that may include thecables 1004, 1007 (FIG. 3) that sense voltages at nodes (not shown) on atransformer to which the cables are attached. As will be describedfurther herein, the control logic 2003 receives data via the cables1004, 1007 indicative of the voltages at the nodes and stores the dataas voltage data 2001. The control logic 2003 performs operations on andwith the voltage data 2001, including periodically transmitting thevoltage data 2001 to the operations computing device 287 (FIG. 2A).

Further, with respect to the transformer monitoring device 1000 depictedin FIG. 3, the transformer monitoring device 1000 comprises the currentsensors (not shown) contained in the sensing unit housing 1005 (FIG. 3)and the sensing unit housing section 1018 (FIG. 3). The current sensorssense current traveling through conductor cables (or neutral cables)around which the sensing unit housings 1005, 1018 are coupled. Thecontrol logic 2003 receives data indicative of current from thesatellite sensing unit 1021 (FIG. 3) via the cable 1011 and dataindicative of the current from the current sensor of the main unit 1001contained in the sensing unit housing section 1018 (FIG. 3). The controllogic 2003 stores the data indicative of the currents sensed as thecurrent data 2002. The control logic 2003 performs operations on andwith the current data 2002, including periodically transmitting thevoltage data 2001 to, for example, the operations computing device 287(FIG. 2A).

Note that the control logic 2003 may perform calculations with thevoltage data 2001 and the current data 2002 prior to transmitting thevoltage data 2001 and the current data 2002 to the operations computingdevice 287. In this regard, for example, the control logic 2003 maycalculate power usage using the voltage data 2001 and current data 2002over time and periodically store resulting values as power data 2020.

The configuration data 2061 comprises data indicative of thresholds forcorresponding to operational data related to the transformers 104, 121(FIG. 1) or the system 100 (FIG. 1) among other data. The configurationdata 2061 comprises data indicative of values such that if a read valuefalls below, meets, or exceeds one of the threshold values stored inconfiguration data 2061, the control logic 2003 triggers an event. Inthis regard, the control logic 2003 compares the read value to a valuein the configuration data 2061. If the comparison qualifies as an event,the control logic 2003 stores data indicative of the event in event data2060. Further, the control logic 2003 transmits data indicative of theevent to the operations computing device 287. Note that different typesof events are described further herein.

Note that the control logic 2003 may transmit data to the operationscomputing device 287 via a power line communication (PLC) method. Inother embodiments, the control logic 2003 may transmit the data via thenetwork 280 (FIG. 2A) wirelessly, optically, or otherwise.

FIGS. 6-10 depict one exemplary practical application, use, andoperation of the transformer monitoring device 1000 shown in the drawingin FIG. 3. In this regard, FIG. 6 depicts a transformer can 1022, whichhouses a transformer (not shown), mounted on a utility pole 1036. One ormore cables 1024-1026 carry current from the transformer can 1022 to adestination (not shown), e.g., consumer premises 106-111 (FIG. 1). Thecables 1024-1026 are connected to the transformer can at nodes1064-1066, respectively. Each node 1064-1066 comprises a conductiveconnector (part of which is sometimes referred to as a bus bar).

FIG. 7 depicts the satellite unit 1021 of the transformer monitoringdevice 1000 being placed on one of the nodes 1064-1066 (FIG. 6), i.e.,in an open position. A technician (not shown), e.g., an employee of autility company (not shown), decouples the latch 1006 (FIG. 3), made upby decoupled sections 1006 a and 1006 b, and places the sections 1088and 1089 around a portion of the node 1064-1066 such that the sensorunit (not shown) interfaces with the node and senses a current flowingthrough the node. FIG. 8 depicts the satellite unit 1021 of thetransformer monitoring device 1000 latched around one of the nodes1064-1066 in a closed position.

FIG. 9 depicts the main unit 1001 of the transformer monitoring device1000 being placed on one of the nodes 1064-1066, i.e., in an openposition. The technician decouples the latch 1002, made up by decoupledsections 1002 a and 1002 b, and places the sections 1016 and 1017 arounda portion of the node 1064-1066 such that the sensor unit (not shown)interfaces with the node and senses a current flowing through the node.FIG. 10 depicts the transformer monitoring device 1000 latched aroundthe node 1064-1066. The main unit 1001 of the transformer monitoringdevice 1000 is latched around one of the nodes 1064-1066 and in a closedposition.

In one embodiment, the cables 1004, 1007 (FIG. 3) of the main unit 1001may be connected to one of the nodes 1064-1066 about which therespective satellite unit 1021 is coupled and one of the nodes 1064-1066about which the main unit 1001 is coupled. One cable is connected to thenode about which the satellite unit 1021 is coupled, and one cable isconnected to the node about which the main unit 1001 is coupled.

During operation, the current detection device contained in the sensingunit housings 1005, 1018 (FIG. 3) sense current from the respectivenodes to which they are coupled. Further, the connections made by thecables 1004, 1007 to the nodes and reference conductor sense the voltageat the respective nodes, i.e., the node around which the main unit iscoupled and the node around which the satellite unit is coupled.

In one embodiment, the analytic logic 308 receives current data for eachnode and voltage data from each node based upon the current sensors andthe voltage connections. The analytics logic 308 uses the collected datato calculate power over a period, which the analytic logic 308 transmitsto the operations computing device 287 (FIG. 2A). In another embodiment,the analytic logic 308 may transmit the voltage data and the currentdata directly to the operations computing device 287 without performingany calculations.

FIGS. 11-13 further illustrate methods that may be employed using thetransformer monitoring device 1000 (FIG. 3) in a system 100 (FIG. 1). Asdescribed hereinabove, the transformer monitoring device 1000 may becoupled to a conductor cable (not shown) or a bushing (not shown) thatattaches the conductor cable to a transformer can 1022 (FIG. 6). Inoperation, the transformer monitoring device 1000 obtains a current andvoltage reading associated with the conductor cable to which it iscoupled, as described hereinabove, and the main unit 1001 (FIG. 3) usesthe current reading and the voltage reading to calculate power usage.

Note for purposes of the discussion hereinafter, a transformermonitoring device 1000 (FIG. 3) comprises two current sensing devices,including one contained in housing 1005 (FIG. 3) and one contained inthe housing 1018 (FIG. 3) of the satellite unit 1021 (FIG. 3) and themain unit 1001 (FIG. 3), respectively.

FIG. 11 is a diagram depicting a distribution transformer 1200 fordistributing three-phase power, which is indicative of a “wye”configuration. In this regard, three-phase power comprises threeconductors providing AC power such that the AC voltage waveform on eachconductor is 120° apart relative to each other, where 360° isapproximately one sixtieth of a second. As described hereinabove,three-phase power is transmitted on three conductor cables and isdelivered to distribution substation transformer 103 (FIG. 1) anddistribution transformer 104 (FIG. 1) on three conductor cables. Thus,the receiving distribution transformer 104 has three winding pairs (onefor each phase input voltage received) to transform the voltage of thepower received to a level of voltage needed for delivery to theconsumers 106-108 (FIG. 1).

In the distribution transformer 1200, three single-phase transformers1201-1203 are connected to a common (neutral) lead 1204. For purposes ofillustration, each transformer connection is identified as a phase,e.g., Phase A/transformer 1201, Phase B/transformer 1202, and PhaseC/transformer 1203.

In the embodiment depicted in FIG. 11, three transformer monitoringdevices 1000 a, 1000 b, and 1000 c (each configured substantially liketransformer monitoring device 1000 (FIG. 3)) are employed to obtain data(e.g., voltage and current data) used to calculate the power at thedistribution transformer 1200.

In this regard, at least one of current sensing devices 1217 oftransformer monitoring device 1000 a is used to collect current data forPhase. A. Notably, the sensing device 1217 of the transformer monitoringdevice 1000 a used to collect current data may be housed in thesatellite unit 1021 (FIG. 3) or the main unit 1001 (FIG. 3), The voltagelead 1004 a of the transformer monitoring device 1000 a is connectedacross the Phase A conductor cable and common 1204 to obtain voltagedata. Note that in one embodiment both current sensing devices in thesatellite unit 1021 and the main unit 1001 (current sensing device 121)may be coupled around the Phase A conductor cable.

Further, a current sensing device 1218 of transformer monitoring device1000 b is used to collect current data for Phase B. As described abovewith reference to Phase A, the sensing device 1218 of the transformermonitoring device 1000 b used to collect current data may be housed inthe satellite unit 1021 (FIG. 3) or the main unit 1001 (FIG. 3), Thevoltage lead 1004 b of the transformer monitoring device 1000 h isconnected across the Phase B conductor cable and common 1204 to obtainvoltage data. Like the Phase A implementation described above, in oneembodiment both current sensing device in the satellite unit 1021 andthe main unit 1001 (current sensing device 1218) may be coupled aroundthe Phase B conductor cable.

Additionally, a current sensing device 1219 of transformer monitoringdevice 1000 c is used to collect voltage and current data for Phase C.As described above regarding Phase A, the sensing device 1219 of thetransformer monitoring device 1000 c that is used to collect currentdata may be housed in the satellite unit 1021 (FIG. 3) or the main unit1001 (I 3). The voltage lead 1004 c of the transformer monitoring device1000 c is connected across the Phase C conductor cable and common 1204to obtain voltage data. Like the Phase A implementation described above,in one embodiment both current sensing devices in the satellite unit1021 and the main unit 1001 (current sensing device 1219) may be coupledaround the Phase C conductor cable.

During monitoring, control logic 2003 (FIG. 5) of the transformermonitoring devices 1000 a-1000 c use current measurements and voltagemeasurements to calculate total power. As described hereinabove, thepower calculated from the measurements made by the transformermonitoring devices 1000 a, 1000 b, and 1000 c may be used in variousapplications to provide information related to the power transmissionand distribution system 100 (FIG. 1).

FIG. 12 is a diagram depicting a distribution transformer 1300 fordistributing three-phase power, which is indicative of a deltaconfiguration. Such distribution transformer 1300 may be used as thedistribution transformer 104 (FIG. 1). The distribution transformer 1300(like the distribution transformer 1200 (FIG. 11)) has three singlephase transformers to transform the voltage of the power received onthree conductor cables (i.e., three-phase power) to a level of voltageneeded for delivery to the consumers 106-108 (FIG. 1).

The distribution transformer 1300 comprises three single-phasetransformers 1301-1303. For purposes of illustration, each transformerconnection is identified as a phase, e.g., Phase A/transformer1301-transformer 1303, Phase B/transformer 1302-transformer 1301, andPhase C/transformer 1303-transformer 1302.

In the embodiment depicted in FIG. 12, two transformer monitoringdevices 1000 d and 1000 e are employed to obtain voltage and currentdata, which are used to calculate power at the distribution transformer1300. In this regard, transformer monitoring device 1000 d is coupledabout one of three incoming conductor cables, identified in FIG. 12 asPhase B, and transformer monitoring device 1000 e is coupled aboutanother one of the three incoming conductor cables, identified in FIG.12 as Phase C. The transformer monitoring devices 1000 d and 1000 e(each configured substantially like transformer monitoring device 1000(FIG. 3)) are employed to obtain data (e.g., voltage and current data)used to calculate the power at the distribution transformer 1300.

In this regard, a current sensing device 1318 of transformer monitoringdevice 1000 d is used to coned current data for Phase B. Notably, thesensing device 1318 of the transformer monitoring device 1000 d used tocollect current data may be housed in the satellite unit 1021 (FIG. 3)or the main unit 1001 (FIG. 3). The voltage leads 1004 d of thetransformer monitoring device 1000 d are connected across the Phase Bconductor cable and the Phase A conductor cable which measures a voltagedifferential. Note that in one embodiment both current sensing devicesin the satellite unit 1021 and the main unit 1001 (current sensingdevice 1318) may be coupled around the Phase B conductor cable. Furthernote that in the delta configuration, Phase A may be arbitrarilydesignated as a “common” such that power may be calculated based on thevoltage differentials between the current-sensed conductor cables andthe designated “common,” Which in the present embodiment is Phase A.

Further, like Phase B measurements, a current sensing device 1319 oftransformer monitoring device 1000 e is used to collect current data forPhase C. As described above regarding Phase B, the sensing device 1319of the transformer monitoring device 1000 e used to collect current datamay be housed in the satellite unit 1021 (FIG. 3) or the main unit 1001(FIG. 3). The voltage leads 1004 e of the transformer monitoring device1000 e are connected across the Phase C conductor cable and Phase Aconductor cable. Notably, in one embodiment both current sensing devicesin the satellite unit 1021 and the main unit 1001 (current sensingdevice 1319) may be coupled around the Phase C conductor cable.

During monitoring, control logic 2003 (FIG. 5) of the transformermonitoring devices 1000 d and 1000 e use current measurements andvoltage measurements to calculate total power. As described hereinabove,the power calculated from the measurements made by the transformermonitoring devices 1000 d and 1000 e may be used in various applicationsto provide information related to the power transmission anddistribution system 100 (FIG. 1).

FIG. 13 is a diagram depicting a distribution transformer 1400 fordistributing power, which is indicative of an open delta configuration.The distribution transformer 1400 has two single phase transformers 1401and 1402 to transform the voltage received to a level of voltage neededfor delivery to the consumers 106-108 (FIG. 1).

The distribution transformer 1400 comprises two single-phasetransformers 1401-1402. In the embodiment depicted in FIG. 13, twotransformer monitoring devices 1000 f and 1000 g are employed to obtainvoltage and current data, which are used to calculate power at thedistribution transformer 1400.

Transformer monitoring device 1000 f is coupled about one of threeconductor cables identified as Phase A and transformer monitoring device1000 g is coupled about another one of the conductor cables identifiedas Phase 13. The transformer monitoring devices 1000 f and 1000 g (eachconfigured substantially like transformer monitoring device 1000 (FIG.3)) are employed to obtain data (e.g., voltage and current data) used tocalculate the power at the distribution transformer 1400.

In this regard, at least one of the current sensing devices 1418 or 1419of transformer monitoring device 1000 f is used to collect voltage andcurrent data for Phase A. While both sensing devices are shown coupledabout Phase A, both are not necessarily needed in other embodiments.Notably, a sensing device of the transformer monitoring device 1000 fused to collect current data may be housed in the satellite unit 1021(FIG. 3) or the main unit 1001 (FIG. 3). The voltage leads 1004 f of thetransformer monitoring device 1000 f are connected across the Phase Aconductor cable and ground. Note that in one embodiment both currentsensing devices in the satellite unit 1021 and the main unit 1001 may becoupled around the Phase A conductor cable, as shown.

Further, current sensing device 1420 housed in the main unit 1001 (FIG.3) of transformer monitoring device 1000 g and current sensing device1421 housed in the satellite unit 1021 (FIG. 3) of transformermonitoring device 1000 g is used to collect current data for Phase B.The voltage lead 1004 g of the transformer monitoring device 1000 g isconnected across the voltage outputs of the secondary of transformer1402.

During monitoring, control logic 2003 (FIG. 5) of the transformermonitoring devices 1000 f and 1000 g uses current measurements andvoltage measurements to calculate total power. As described hereinabove,the power calculated from the measurements made by the transformermonitoring devices 1000 f and 1000 g may be used in various applicationsto provide information related to the power transmission anddistribution system 100 (FIG. 1).

FIG. 14 depicts an exemplary polyphase distribution transformer monitor(PDTM) 1499 in accordance with an embodiment of the present disclosure.In one embodiment, polyphase refers to a system for distributingalternating current electrical power and has one or more electricalconductors wherein each carry alternating currents having time offsetsone from the others. Note that while the PDTM 1499 is configured tomonitor up to four conductors (not shown), the PDTM 1499 may be used tomonitor one or more conductors, e.g., single phase or two-phase power,which is substantially like monitoring three-phase power, which isdescribed further herein.

Notably, regarding FIG. 2A, the PDTM 1.499 may serve the purpose andfunctionality and is a type of transformer monitoring device 244, 243(FIG. 2A). Thus, the 1499 collects power and electrical characteristicdata related to a distribution transformer 104, 121 (FIG. 1).

Note that the PDTM 1499 may also comprise sensors or probes forcollecting data indicative of ambient temperature, actual firetemperature, ground and/or surface temperature, vibration, smoke,nuclear radiation, noxious gases, humidity, transformer externaltemperature, and geo-positioning. In such a scenario, if one of themonitored characteristics indicates a problem the transformer monitoringdevice 1499 is configured to notify utility personnel or anotherindividual in charge of emergency situations.

In particular, the transformer monitoring device 1499 may comprise asmoke and noxious gases sensor, and ambient temperature sensor, and aground and/or surface temperature sensor, and an actual fire temperaturesensor, and a humidity sensor. In such a scenario, the transformermonitoring device 1499 can detect fire in proximity to the transformerto which the transformer monitoring device 1499 is coupled. The smokesensor detects the smoke from a fire. The ambient temperature sensordetects the temperature surrounding the transformer monitoring device1499, and the ground and/or surface temperature sensor detects theactual fire, ground, or surface temperature. Taken together, dataindicative of the smoke, the ambient temperature, and the actual fire,ground and/or surface temperature may be compared to normalized data,and if the data indicative of the smoke, the ambient temperature, andthe actual fire, ground and/or surface temperature exceeds a particularvalue, a fire is indicated. When a fire is indicated, the transformermonitoring device 1499 reports the fire to a computing device of autility company, to a handheld device of personnel, or to a third-partycomputing device.

The PDTM 1499 comprises a control box 1498, which is a housing thatconceals a plurality of electronic components that control the PDTM1499. Additionally, the PDTM 1499 comprises a plurality of satellitecurrent sensors 1490-1493.

The satellite current sensors 1490-1493 are structurally andfunctionally substantially like the satellite unit 1021 describedregarding FIGS. 3, 7, and 8. In this regard, the satellite currentsensors 1490-1493 detect a current through an electrical cable, bus bar,or any other type of node through which current passes into and/or froma distribution transformer, such as the distribution transformer shownin 6.

Further, the satellite current sensors 1490-1493 are electricallyconnected to the control box 1498 (and to the electronics (not shown)contained therein). In this regard, the satellite current sensor 1490may be electrically connected via connectors 1464, 1460 on the satellitecurrent sensor 1490 and the control box 1498, respectively, by a voltagecurrent cable 1480. Similarly, the satellite current sensor 1491 iselectrically connected via connectors 1465, 1461 on the satellitecurrent sensor 1491 and the control box 1498, respectively, by a voltagecurrent cable 1481, the satellite current sensor 1492 is electricallyconnected via connectors 1466, 1462 on the satellite current sensor 1492and the control box 1498, respectively, by a voltage current cable 1482,and the satellite current sensor 1493 is electrically connected viaconnectors 1467, 1463 on the satellite current sensor 1493 and thecontrol box 1498, respectively, by a voltage current cable 1483.

Note that the current cables 1480-1483 may be an American NationalStandards Institute (ANSI)-type cable. In one embodiment, the currentcables 1480-1483 are insulated, and may be any other type of cable knownin the art or future-developed configured to transfer data indicative ofcurrent measurements made by the satellite current sensors 1490-1493 tothe control box 1498.

In addition, each current cable 1480-4483 is further associated with avoltage cable 1484-1487. In this regard, each voltage cable 1484-1487extends from the connectors 1460-1463 on the control box 1498 andterminates with ring terminals 1476-1479, respectively.

Note that in one embodiment of the PDTM 1499 connectors 1460-1463 may beunnecessary. In this regard, the conductors 1480-4483 and conductors1484-4487 may be connected to electronics directly without use of theconnectors 1460-1463.

In one embodiment, the current sensors 1490-1493 and the correspondingvoltage cables 1484-4487 are not permanently mounted to the control box1498 but are mounted to the control box 1498 via external weatherproofconnectors. In such a scenario, the current sensors 1490-1493 may bedecoupled from the control box 1498 and replaced, for example if one ormore of the current sensors 1490-1493 are not working properly. Further,the corresponding voltage cables 1484-1487 may also be decoupled andreplaced, for example if the corresponding voltage cables 1484-1487 arenot working properly.

During operation, one or more of the satellite current sensors 1490-1493are installed about conductors (e.g., cables), bus bars, or other typeof node through which current travels. In addition, each of the ringterminals 1476-1479, respectively, are coupled to the conductor, busbar, or other type of node around which their respective satellitecurrent sensor 1490-1493 is installed.

More specifically, each satellite current sensor 1490-1493 takes currentmeasurements over time of current that is flowing through the conductorcable, bus bar, or node around which it is installed. Also, over time,voltage measurements are sensed via each of the satellite currentsensor's respective voltage cables 1484-1487. As will be describedherein, the current measurements and voltage measurements taken overtime are correlated and thus used to determine power usage correspondingto the conductor cable, bus bar, or node.

FIG. 15A depicts an exemplary embodiment of a controller 1500 that ishoused within the control box 1498. As shown by FIG. 15A, the controller1500 comprises control logic 1503, voltage data 1501, current data 1502,and power data 1520 stored in memory 1522. In addition, the controller1500 comprises event data 1570 and configuration data 1571.

The control logic 1503 controls the functionality of the controller1500, as will be described in more detail hereafter. It should be notedthat the control logic 1503 can be implemented in software, hardware,firmware, or any combination thereof. In an exemplary embodimentillustrated in FIG. 15A, the control logic 1503 is implemented insoftware and stored in memory 1522.

Note that the control logic 1503, when implemented in software, can bestored and transported on any computer-readable medium for use by or inconnection with an instruction execution apparatus that can fetch andexecute instructions. In the context of this document, a“computer-readable medium” can be any means that can contain or store acomputer program for use by or in connection with an instructionexecution apparatus.

The exemplary embodiment of the controller 1500 depicted by FIG. 15comprises at least one conventional processing element 1504, such as adigital signal processor (DSP) or a central processing unit (CPU), thatcommunicates to and drives the other elements within the controller 1500via a local interface 1505, which can include at least one bus. Further,the processing element 1504 is configured to execute instructions ofsoftware, such as the control logic 1503.

In addition, a network interface 1561, such as a modem or wirelesstransceiver, enables the controller 1500 to communicate with the network280 (FIG. 2A).

In one embodiment, the controller 1500 further comprises a communicationinterface 1560. The communication interface 1560 is any type ofinterface that when accessed enables power data 1520, voltage data 1501,current data 1502, or any other data collected or calculated by thecontroller 1500 to be communicated to another system or device, e.g.,the computing device 287.

As an example, the communication interface 1560 may be a serial businterface that enables a device that communicates serially to retrievethe identified data from the controller 1500. As another example, thecommunication interface 1560 may be a universal serial bus (USB) thatenables a device configured for USB communication to retrieve theidentified data from the controller 1500. Other communication interfacesmay use other methods and/or devices for communication including radiofrequency (RF), cellular, power line, Wi-Fi, and/or opticalcommunications.

The controller 1500 further comprises one or more current cableinterfaces 1550-1553 and voltage cable interfaces 1554-1557 that receivedata transmitted via the current cables 1480-1483 (FIG. 14) and voltagecables 1484-1487 (FIG. 14), respectively. In this regard, each currentcable interface/voltage cable interface pair is associated with a singleconnector. For example, connector 1460 receives cables 1480 (FIG. 14)(current) and 1484 (FIG. 14) (voltage), and the current cable interface1550 receives data indicative of current and the voltage cable interface1554 receives data indicative of current associated with the conductorabout which the satellite current sensor 1490 is installed.

Similarly, connector 1461 receives cables 1481 (FIG. 14) (current) and1485 (voltage) (FIG. 14), and the current cable interface 1551 receivesdata indicative of current and the voltage cable interface 1555 receivesdata indicative of current associated with the conductor about which thesatellite current sensor 1491 (FIG. 14) is installed. The connector 1462receives cables 1482 (FIG. 14) (current) and 1486 (FIG. 14) (voltage),and the current cable interface 1552 receives data indicative of currentand the voltage cable interface 1556 receives data indicative of currentassociated with the conductor about which the satellite current sensor1492 (FIG. 14) is installed. Finally, connector 1463 receives cables1483 (FIG. 14) (current) and 1487 (FIG. 14) (voltage), and the currentcable interface 1553 receives data indicative of current and the voltagecable interface 1557 receives data indicative of voltage associated withthe conductor about which the satellite current sensor 1493 (FIG. 14) isinstalled

During operation, the control logic 1503 receives the voltage andcurrent data from the interfaces 1550-1557 and stores the current dataas current data 1502 and the voltage data as voltage data 1501. Thecontrol logic 1503 performs operations on and with the voltage data 1501and current data 1502, including periodically transmitting the voltagedata 1501 and current data 1502 to, for example, the operationscomputing device 287 (FIG. 2A). Note that the control logic 1503 mayperform calculations with the voltage data 1501 and the current data1502 prior to transmitting the voltage data 1501 and the current data1502 to the operations computing device 287. For example, the controllogic 1503 may calculate power usage using the voltage data 1501 andcurrent data 1502 over time and periodically store resulting values aspower data 1520.

During operations, the control logic 1503 may transmit data to theoperations computing device 287 via the cables using a power linecommunication (PLC) method. In other embodiments, the control logic 1503may transmit the data via the network 280 (FIG. 2A) wirelessly,optically, or otherwise.

The configuration data 1571 comprises data indicative of thresholds foroperational data related to the transformers 104, 121 (FIG. 1) or thesystem 100 (FIG. 1). The configuration data 1571 may comprise dataindicative of values of such that if a read value falls below, meets, orexceeds one of the threshold values stored in configuration data 1571,the control logic 1503 triggers an event. In this regard, the controllogic 1503 compares the read value to a value in the configuration data1571. If the comparison qualifies as an event, the control logic 1503stores data indicative of the event in event data 1570. Further, thecontrol logic 1503 transmits data indicative of the event to theoperations computing device 287. Note that types of events are describedfurther herein.

FIG. 15B depicts another embodiment of an exemplary controller 1593 thatmay be housed within the control box 1498 (FIG. 14). As shown by FIG.15B, the controller 1593 comprises control logic 1586, which behavessimilarly to the control logic 1503 (FIG. 15A) shown and described withreference to FIG. 15A. However, in the embodiment depicted in FIG. 15B,the control logic 1586 resides on a microprocessor 1585 thatcommunicates with an internal bus 1584. The control logic 1586 may besoftware, hardware, or any combination thereof.

In one embodiment, the control logic 1586 is software and is stored in amemory module (not shown) on the microprocessor 1585. In such anembodiment, the control logic 1586 may be designed and written on aseparate computing device (not shown) and loaded into the memory moduleon the microprocessor 1585.

Additionally, the controller 1593 comprises a microprocessor 1578 andFLASH memory 1579 that communicate with the microprocessor 1585 over theinternal bus 1584. Further, the controller 1593 comprises aninput/output interface 1583 and a communication module 1587 each ofwhich communicates with the microprocessor 1585 directly. Note that theinterface 1583 and the communication module 1587 may communicate withthe microprocessor 1585 indirectly, e.g., vie the buses 1584 or 1585, inother embodiments.

The microprocessor 1578 is electrically coupled to four current sensors1570-1573 and four voltage inputs 1574-1577. Note that with reference toFIG. 14, such current sensors 1570-1573 and voltage inputs 1574-1577correlate with satellite units 1490-1493 (FIG. 14) and voltage leads1476-1479 (FIG. 14), respectively.

While four current sensors 1570-1573 and respective voltage inputs1574-1577 are depicted in FIG. 15B, there can be additional or fewercurrent sensors 1570-1573 and respective voltage inputs 1574-1577 usedin other embodiments. In this regard, the controller 1593 may be used togather information related to a single phase or two-phase power usingdevice, e.g., a transformer, in other embodiments.

Note that the communication module 1587 is any type of communicationmodule known in the art or future-developed. The communication module1587 receives data from the microprocessor 1585 and transmits thereceived data to another computing device. For example, with referenceto FIG. 2A, the communication module 1587 may be communicatively coupledto the operations computing device 287 (FIG. 2A) and transmit thecurrent data 1594 and the voltage data 1595 to the operations computingdevice 287. In one embodiment, the communication module 1587 may bewirelessly coupled to the operations computing device 287; however,other types of communication are possible in other embodiments.

The controller 1593 further has electronically erasable programmableread-only memory (EEPROM) 1589, a real-time clock 1590, and atemperature sensor 1591. The EEPROM 1589, the clock 1590, and the sensor1591 communicate with the microprocessor 1585 via another internal bus1588.

Note that as shown in the embodiment of the controller 1593, thecontroller 1593 may comprise two separately accessible internal buses,e.g., buses 1584 and 1588. However, additional, or fewer internal busesare possible in other embodiments.

During operation, the microprocessor 1578 receives signals indicative ofcurrent and voltage from current sensors 1570-1573 and voltage inputs1574-1577, respectively. When received, the signals are analog signals.The microprocessor 1578 receives the analog signals, conditions theanalog signals, e.g., through filtering, and converts the analog signalsindicative of current and voltage measurements into transient currentdata 1594 and transient voltage data 1595. The microprocessor transmitsthe data 1594 and 1595 to the microprocessor 1585, and the control logic1586 stores the data 1594 and 1595 as current data 1582 and voltage data1581, respectively, in the FLASH memory 1579. Note that while FLASHmemory 1579 is shown, other types of memory may be used in otherembodiments.

The control logic 1586 may further compute power usage based upon thedata 1594 and 1595 received from the microprocessor 1578. In thisregard, the control logic 1586 may store the power computations in theFLASH memory 1579 as power data 1580.

Further, during operation, the control logic 1586 may receive real-timetime stamps associated with a subset of the digital data 1594 and 1595received from the microprocessor 1578. In such an embodiment, inaddition to data indicative of the current and voltage readings taken bythe current sensors 1570-1573 and the voltage inputs 1574-1577, thecontrol logic 1586 may also store associated with the current andvoltage data indicative of the time that the reading of the associatedcurrent and/or voltage was obtained. Thus, the FLASH memory 1579 maystore historical data for a given time.

During operation, a user (not shown) may desire to load an updatedversion or modified version of the control logic 1586 onto themicroprocessor 1585. In this scenario, the user may transmit data (notshown) indicative of a modified version of the control logic 1586 viathe communication module 1587. Upon receipt by the control logic 1586,the control logic 1586 may store data 1599 indicative of the modifiedversion in the FLASH memory 1579. The microprocessor 1585 may thenreplace the control logic 1586 with the modified control logic data 1599and continue operation executing the modified control logic data 1599.

The EEPROM 1589 stores configuration data 1592. The configuration data1592 is any type of data that may be used by the control logic 1586during operation. For example, the configuration data 1592 may storedata indicative of scale factors for use in calibration of thecontroller 1593, including offset or other calibration data. Theconfiguration data 1592 may be stored in the EEPROM 1589 atmanufacturing. In other embodiments, the configuration data 1592 may beupdated via the communication module 1587 or the interface 1583, asdescribed hereinafter.

Additionally, the input/output interface 1583 may be, for example, anoptical port that connects to a computing device (not shown) or otherterminal for interrogation of the controller 1593. In such anembodiment, logic (not shown) on the computing device may request data,e.g., power data 1580, voltage data 1581, current data 1582, orconfiguration data 1592, via the interface 1583, and in response, thecontrol logic 1586 may transmit data indicative of the data 1580-1582 or1592 via the interface 1583 to the computing device.

Further, the temperature sensor 1591 collects data indicative of atemperature of the environment in which the sensor resides. For example,the temperature sensor 1591 may obtain temperature measurements withinthe housing 1498 (FIG. 14). The control logic 1586 receives dataindicative of the temperature readings and stores the data astemperature data 1598 in FLASH memory 1579. As described hereinaboveregarding time stamp data, the temperature data 1598 may also becorrelated with voltage data 1581 and/or current data 1582.

FIGS. 16-18 depict exemplary installations on differing types ofelectrical service connections for three-phase electric powerinstallations. In this regard, FIG. 16 depicts a four-wire grounded“Wye” installation 1600, FIG. 17 depicts a three-wire Delta installation1700, and FIG. 18 depicts a four-wire tapped Delta neutral groundedinstallation 1800. Each of these is discussed separately in the contextof installing and operating a DIM 1000 or a PDTM 1499 for the collectionof voltage and current data for the calculation of power usage data onthe secondary windings (shown per FIGS. 16-18) for each type ofinstallation.

FIG. 16 is a diagram depicting a Wye installation 1600 (also referred toas a “star” three-phase configuration. While the Wye installation can bea three-wire configuration, the installation 1600 is implemented as afour-wire configuration. The installation comprises the secondarywindings of a transformer, which are designated generally as 1601. Theinstallation comprises four conductors, including conductors A, B, C,and N (or neutral), where N is connected to ground 1602. In theinstallation 1600, the magnitudes of the voltages between each phaseconductor (e.g., A, B, and C) are equal. However, the Wye configurationthat includes a neutral also provides a second voltage magnitude, whichis between each phase and neutral, e.g., 208/120V systems.

As an example, during operation, the PDTM 1499 (FIG. 14) is connected tothe installation 1600 as indicated. The satellite current sensor 1490 iscoupled about conductor A, and its corresponding voltage ring terminal1476 is electrically coupled to conductor A. Thus, the control logic1503 (FIG. 15A) receives data indicative of voltage and current measuredfrom conductor A and stores the corresponding data as voltage data 1501(FIG. 15A) and current data 1502 (FIG. 15A). Similarly, satellitecurrent sensor 1491 (FIG. 14) is coupled about conductor B, and itscorresponding voltage ring terminal 1477 (FIG. 14) is electricallycoupled to conductor B, satellite current sensor 1492 (FIG. 14) iscoupled about N (neutral), and its corresponding voltage ring terminal1478 (FIG. 14) is electrically coupled to N, and satellite, currentsensor 1493 (FIG. 14) is coupled about conductor C, and itscorresponding voltage ring terminal 1479 (FIG. 14) is electricallycoupled to conductor C. Thus, over time the control logic 1503 receivesand collects data indicative of voltage and current measured from eachconductor and neutral and stores the corresponding data as voltage data1501 and current data 1502. The control logic 1503 uses the collecteddata to calculate power usage over the period for which voltage andcurrent data is received and collected.

Further, FIG. 17 is a diagram depicting a Delta installation 1700. TheDelta installation 1700 shown is a three-wire configuration. Theconnections made in the Delta configuration are across each of the threephases, or the three secondary windings of the transformer. Theinstallation comprises the secondary windings of a transformer, Whichare designated generally as 1701. The installation comprises threeconductors (i.e., three-wire), including conductors A, B, and C. In theinstallation 1700, the magnitudes of the voltages between each phaseconductor (e.g., A, B, and C) are equal.

During operation, the PDTM 1499 (FIG. 14) is connected to theinstallation 1700 as indicated. In this regard, satellite current sensor1490 is coupled about conductor A, and its corresponding voltage ringterminal 1476 is electrically coupled to conductor A. Thus, the controllogic 1503 receives data indicative of voltage and current measured fromconductor A and stores the corresponding data as voltage data 1501 andcurrent data 1502, respectively. Similarly, satellite current sensor1491 is coupled about conductor B, and its corresponding voltage ringterminal 1477 is electrically coupled to conductor B, and satellitecurrent sensor 1492 is coupled about C, and its corresponding voltagering terminal 1478 is electrically coupled to C. Regarding the fourthsatellite current sensor 1492, because the installation 1700 is athree-wire set up, the fourth satellite current sensor 1493 is notneeded, and may therefore not be coupled to a conductor. Over time thecontrol logic 1503 receives and collects data indicative of voltage andcurrent measured from each conductor (A, B, and C and stores thecorresponding data as voltage data 1501 and current data 1502. TheControl logic 1503 may then use the collected data to calculate powerusage over the period for which voltage and current data is received andcollected.

FIG. 18 is a diagram depicting a Delta installation 1800 in which onewinding is center-tapped to ground 1802 which is often referred to as a“high-leg Delta configuration.” The Delta installation 1800 shown is afour-wire configuration. The connections made in the Delta installation1800 are across each of the three phases and neutral (or ground), or thethree secondary windings of the transformer and ground. The installation1800 comprises the secondary windings of a transformer, which aredesignated generally as 1801. The installation comprises threeconductors, including conductors A, B, and C and the center-tapped N(neural) wire. The installation 1800 shown is not symmetrical andproduces three available voltages.

As an example, during operation, the PDTM 1499 (FIG. 14) is connected tothe installation 1801 as indicated. In this regard, satellite currentsensor 1490 is coupled about conductor A, and its corresponding voltagering terminal 1476 is electrically coupled to conductor A. Thus, thecontrol logic 1503 receives data indicative of voltage and currentmeasured from conductor A and stores the corresponding data as voltagedata 1501 and current data 1502. Similarly, satellite current sensor1491 is coupled about conductor and its corresponding voltage ringterminal 1477 is electrically coupled to conductor B, satellite currentsensor 1492 is coupled about N, and its corresponding voltage ringterminal 1478 is electrically coupled to N, and satellite current sensor1493 is coupled about conductor C, and its corresponding voltage ringterminal 1479 is electrically coupled to C. Like the installation 1600,over time the control logic 1503 receives and collects data indicativeof voltage and current measured from each conductor (A, B, C, and N) andstores the corresponding data as voltage data 1501 and current data1502, The control logic 1503 may then use the collected data tocalculate power usage over the period for which voltage and current datais received and collected.

FIG. 19 is a flowchart depicting exemplary architecture andfunctionality of the system 100 depicted in FIG. 1.

In step 1900, electrically interfacing a first transformer monitoringdevice 1000 (FIG. 3) to a first electrical conductor of a transformer ata first location on a power grid, and in step 1901 measuring a firstcurrent through the first electrical conductor and a first voltageassociated with the first electrical conductor.

In step 1902 electrically interfacing a second transformer monitoringdevice 1000 with a second electrical conductor electrically connected tothe transformer, and in step 1903 measuring a second current through thesecond electrical conductor and a second voltage associated with thesecond electrical conductor.

Finally, in step 1904, calculating values indicative of powercorresponding to the transformer based upon the first current and thefirst voltage and the second current and the second voltage.

FIG. 20 is an exemplary embodiment of a transformer monitoring and dataanalysis system 2100 in accordance with an embodiment of the presentdisclosure. The system 2100 comprises a plurality of DTM devices 1000.Note that structure, function, and operation of the DTM devices 1000 aredescribed above with reference to FIGS. 3, 5, and 7-10.

Further note that three DTM devices 1000 are shown in FIG. 20. However,additional, or fewer DTM devices 1000 may be used in other embodimentsof the present disclosure.

Each DTM device 1000 is installed around a node (not shown) of atransformer 2101. Each DTM device 1000 collects data indicative ofcurrent flow and voltage of their respective node. This collected datais transmitted to a computing device 2102, via a communication interface2050 (FIG. 5). As described hereinabove, the communication interface2050 may employ any type of technology that enables the DTMs 1000 tocommunicate with the computing device 2102. As a mere example, thecommunication interface 2050 may be a wireless transceiver, and each DTMcommunicates its collected data to the computing device 2102 wirelessly.In another embodiment, the DTMs 1000 may communicate via an opticalconnection.

In one embodiment, the computing device 2102 is configured to analyzethe data received from the DTM devices 1000 to determine if an event hasoccurred for which reporting is appropriate, e.g., a power outage. Inanother embodiment, the DTMs 1000 determine whether an event hasoccurred and transmits data indicative of the event to the computingdevice 2101, which is described with reference to FIG. 5 and is furtherdescribed herein.

In the embodiment wherein the computing device 2102 determines an event,the computing device 2102 determines at the very least when an event hasoccurred. Events are described further herein. Also, the computingdevice 2102 transmits a notification to utility personnel and/ortransmits data to a Web interface 2104 that may be accessed by a user.Note that in the described embodiment, the determination of an event iseffectuated by the computing device 2101.

In another embodiment, each DTM 1000 is configured to analyze the datareceived and determine when an event has occurred. In such anembodiment, the DTM 1000 transmits data indicative of the event to thecomputing device 2102, and the computing device 2102 transmitsnotifications, serves informative Web pages via a Web interface 2104,and tracks historical data, as described hereafter.

In the embodiment, the computing device 2102 collects, compiles, andstores at the very least historical data related to each DTMcommunication. The computing device 2102 is further configured to exportraw data 2103 of the historical data via any type of mechanism capableof exporting raw data including, but not limited to distributed networkprotocol (dnp), file transfer protocol (ftp), or web services.

FIG. 21 is an exemplary embodiment of another transformer monitoring anddata analysis system 2200 in accordance with an embodiment of thepresent disclosure. However, different from the system 2100 (FIG. 20),system 2200 comprises a polyphase distribution transformer monitor(PDTM) 1499.

As described hereinabove with reference to FIGS. 14 and 15A, the PDTMcomprises a plurality of satellite units 1490-1493. Each satellite unit1490-1493 is installed around a node (not shown) of the transformer 2101or other type of electricity delivery system. Further, each satelliteunit 1490-1493 is configured to measure voltage and current in each oftheir respective nodes. The measurements collected are transmitted tothe control box 1498 via wires or other type of transmission.

Note that while four satellite units are shown in FIG. 21, fewer oradditional satellite units may be used. As an example, one satelliteunit may be used to obtain measurements from a single-phase transformer.Additionally, three satellite units may be used for three phasetransformers.

The control box 1498 comprises a communication interface 1560 (FIG.15A). The communication interface 1560 is configured to transmit thecollected data to the computing device 2102. The computing device 2102behaves as described with reference to FIG. 20, that is exporting rawdata 2103 and providing data to Web interfaces 2104.

In one embodiment, the computing device 2102 is configured to analyzethe data received from the DTM devices 1000 to determine if an event hasoccurred for which reporting is appropriate, e.g., a power outage. Inanother embodiment, the DTMs 1000 determine whether an event hasoccurred and transmits data indicative of the event to the computingdevice 2101, which is described with reference to FIG. 5 and is furtherdescribed herein.

FIG. 22 depicts an exemplary embodiment of the computing device 2102such is depicted in FIGS. 21 and 22. As shown by FIG. 22, the computingdevice 2102 comprises computing device control logic 2308, meter data2390, transformer data 2391, line data 2392, event data 2313, andconfiguration data 2312, all stored in memory 2300.

The computing device control logic 2308 generally controls thefunctionality and operations of the computing device 2102, as will bedescribed in more detail hereafter. It should be noted that thecomputing device control logic 2308 can be implemented in software,hardware, firmware, or any combination thereof. In an exemplaryembodiment illustrated in FIG. 22, the computing device control logic2308 is implemented in software and stored in memory 2300.

Note that the computing device control logic 2308, when implemented insoftware, can be stored and transported on any computer-readable mediumfor use by or in connection with an instruction execution apparatus thatcan fetch and execute instructions. In the context of this document, a“computer-readable medium” can be any means that can contain or store acomputer program for use by or in connection with an instructionexecution apparatus.

The exemplary embodiment of the computing device 2102 depicted by FIG.22 comprises at least one conventional processing element 2302, such asa digital signal processor (DSP) or a central processing unit (CPU),which communicates to and drives the other elements within theoperations computing device 2102 via a local interface 2301, which caninclude at least one bus. Further, the processing element 2302 isconfigured to execute instructions of software, such as the computingdevice control logic 2308.

In addition, the computing device 2102 comprises a network interface2305. The network interface 2305 is any type of interface that enablesthe computing device 2102 to export raw data 2103 or deliver webinterfaces 2104 to a user (not shown). As an example, the networkinterface 2305 may communicate with the Internet (not shown) to deliverthe Web Interfaces 2104 to a user's browser or communicate with a widearea network (WAN) to deliver exported raw data 2103. Notably, thenetwork interface 2305 may enable wired and wireless communication.

The remaining discussion focuses on the PDTM system 2200 depicted inFIG. 21. Note however, that the transformer 2101, the computing device2102, the exported raw data 2103, and the Web interfaces 2104 areelements common to both system 2100 (FIG. 20) and system 2200 (FIG. 21).Thus, when describing operation of the computing device 2102, suchoperations can also be attributed to the system 2100 depicted in FIG.20.

Note that in one embodiment the configuration data 2312 comprises dataindicative of ranges of operation tolerances expected at the transformerand program tolerances for each phase or node of the transformer 2101(FIGS. 21 and 22). During operation, the computing device control logic2308 analyzes the data received from the controller 1500 (FIG. a). Inone embodiment, the computing device control logic 2308 compares thevalue received to the corresponding threshold in the configuration data2312. If the comparison indicates that the value meets, falls below orexceeds a threshold value, the computing device control logic 2308automatically generates a notification to be sent to utility personnel(not shown) who have been designated to oversee the condition indicated.

Note that notification may be effectuated using a variety ofcommunication modes. For example, the computing device control logic2308 may email or text the utility personnel. In another embodiment, thecomputing device control logic 2308 may automatically call the utilitypersonnel with a preprogrammed message. Additionally, the computingdevice control logic 2308 may store the data received and/or the resultsof the analysis in historic data 2306.

In another embodiment, which is described hereinabove regarding FIG. 5and FIG. 15A, the DTM 1000 (FIG. 5) and the PDTM (FIG. 15A) have controllogic 2003, 1503, respectively. In operation, the control logic 2003(DTM) stores event data 2060 (FIG. 5) in memory 2000 (FIG. 5). Further,the control logic 1503 (PDTM) stores event data in memory 1522. Thecontrol logic 2003, 1503 (FIG. 15A) stores event data based uponpredetermined thresholds, which are stored as configuration data 2061(FIG. 5) and configuration data 1571 (FIG. 15A), respectively. If anevent of interest occurs, the control logic 2003, 1502 transmit dataindicative of the event to the computing device 2101. Upon receipt, thecomputing device control logic 2308 determines whether to take anaction, e.g., transmit a notification to utility personnel. Thenotifications may be for many different types of events. The followingdiscussion outlines exemplary events.

Note that for ease of discussion, the control logic 2003 (DTM) and thecontrol logic 1503 (PDTM) is hereinafter referred to collectively as“Control Logic.”

In one embodiment, the power may be lost (or restored) at thetransformer 2101 (FIG. 21). Prior to powering down, the Control Logic isconfigured to transmit a message to the computing device 2102 that powerhas been lost at the transformer. In response, the computing device 2102stores data indicative of the event, updates a status of thetransformer, and transmits an instant message (e.g., a text message) aswell as time-stamped event data that indicates the time power was lost.Once power is restored, the Control Logic transmits a message to thecomputing device 2102 indicating that the power is restored to thetransformer 2101. The computing device 2102 determines, based upon apredetermined setting, if a notification is indicated in theconfiguration data, when to notify the utility personnel, and to whom tosend the notification. This event notification allows utilities accuratepower loss evaluation and reporting.

Note that when power is lost at the transformer 2101, power is also lostat the DTM 1000 (FIG. 20) or the PDTM 1499 (FIG. 21). In the event poweris lost, the DTM and the PDTM devices comprise a circuit, which includesan electronic component, e.g., a supercapacitor, that enables theControl Logic to continue operating for a time after power is lost.During this period, the Control Logic sends a notification as describedhereinabove to the computing device 2102.

In one embodiment, the Control Logic monitors the ambient temperaturewithin the DTM 1000 (FIG. 20) or the PDTM 1499 (FIG. 21) or the ambienttemperature of the transformer 2101. In either case, the Control Logicmay periodically transmit, or transmit upon request, data indicative ofthe temperature being monitored. If the value exceeds a threshold value,the Control Logic transmits data indicative of the event to thecomputing device 2102. At the computing device 2102, the control logic2308 determines whether to send a notification, to whom to send thenotification, and when to send the notification. Further, the controllogic 2308 stores event data 2313 in memory 2300. In one embodiment, theControl Logic transmits the total power being consumed by the satelliteunits 1490-1493 (FIG. 21) or each DTM 1000 (FIG. 20). If the total powerequals and/or exceeds a threshold value or equals and/or falls below athreshold value, the Control Logic transmits data indicative of thepower consumption to the computing device 2102. The control logic 2308determines whether to transmit a message to utility personnel, to whomto transmit the message and when to transmit the message. Note that inone embodiment, the computing device 2102 may compare the dataindicative of the power consumption to configuration data 2312, andtransmit a message based upon the comparison.

In one embodiment, the Control Logic monitors the reverse power beingsupplied through a distributed generation (DG) or a distributed energyresources (DER). If the total reverse power exceeds a high thresholdlimit as indicated in the configuration data, the Control Logictransmits data indicative of the reverse power to the computing device2102, and the control logic 2308 determines whether to send anotification to utility personnel, to whom to send the notification, andwhen to send the notification.

Additionally, the Control Logic independently monitors the three phasesof power, phase A, B, and C for energy, voltage, and current. TheControl Logic compares the data indicative of the energy, voltage, andcurrent with threshold values in the configuration data 2312, and if athreshold value is met or exceeded, the Control Logic transmits dataindicative of the energy, voltage, and current to the computing device2102. The computing device 2102 stores the data as transformer data2391. The computing device control logic 2308 compares the meter data2390 with corresponding configuration data 2312, and determines whetherto transmit a notification, to whom to transmit the notification, andwhen to transmit a notification based on the tolerances that areviolated.

In one embodiment, the Control Logic measures voltage imbalance of thetransformer 2101. If the voltages are imbalanced, the Control Logictransmits a notification to the computing device 2102. The computingdevice control logic 2308 determines whether to send a notification, towhom to send the notification, and when to send the notification. As anexample, the values indicative of voltage imbalance may exceed theindustry standard balance, i.e., 2-4% imbalance is acceptable, andgreater imbalances can be harmful to downstream equipment andappliances. If the Control Logic determines that the imbalance isgreater than 2-4%, the Control Logic sends a notification to thecomputing device 2102, and the computing device control logic 2308determines whether to send utility personnel a notification, to whom tosend the notification, and when to send the notification.

In one embodiment, the Control Logic monitors a power factor for thetransformer 2101. If the power factor exceeds a threshold value, theControl Logic transmits data indicative of the power factor to thecomputing device 2102. In response, the computing device control logic2308 determines whether to send a notification, to whom to send thenotification, and when to send the notification.

In one embodiment, the Control Logic is configured to monitor powerbased upon different threshold limits for different parts of a 24-hourperiod. For example, some assets may not be active at different times ofthe day, e.g., photovoltaic system. If the Control Logic determines thatthe power monitored meets or exceeds or falls below the thresholdvalues, the Control Logic transmits data indicative of the power to thecomputing device 2102. The computing device control logic 2308 isconfigured to determine whether to transmit a notification to utilitypersonnel, to whom to send the notification, and when to send thenotification.

Other events that are monitored and analyzed by the Control Logicinclude high and low per phase, high root mean square (RMS) current perphase, high and low frequency, and period overall, and high diversion.Additionally, other operational values that generate events include lowRMS current per phase, RMS voltage imbalance, RMS current imbalance,forward interval kilowatt (KW) and kilovolt-amp (KVA), reverse intervalKW and KVA, and low cellular signal strength. In one embodiment, theenergy data (KW) may be reconciled against downstream meters to identifypower theft or a mismatch of transformers to meters. In any event, inone embodiment, the Control Logic is configured to determine whether totransmit data indicative of the event to the computing device 2102, andthe computing device control logic 2308 determines whether to notifyutility personnel, to whom to send a notification, and when to send thenotification. There is often unmetered authorized energy consumption,which includes consumption by streetlights, traffic lights, etc. TheControl Logic is configured to extract the unmetered authorized energyconsumption from the remaining energy consumption. Thus, in determiningthe difference between the transformer and associated downstream meters,the Control Logic can with some degree of certainty determine that theenergy difference may be due to pilfered power, or there is a mismatchof transformer to meter association.

Further, transformer energy data may also be used to properly identifywhich downstream meters are associated with their respectivetransformer. In this regard, the system 1499 remedies this scenario byusing the power data to identify the proper meter-transformerassociation.

FIG. 23 shows a system 2407 that comprises another embodiment of atransformer monitoring device 2400. The system 2407 further comprisesthe central computing device 2102 that is communicatively coupled to thetransformer monitoring device 2400 via a network 2408.

The transformer monitoring device 2400 is like the main unit 1000 shownin FIG. 3; however, inclusion of the satellite unit 1021 (FIG. 3) isoptional. Note that like numerals are used from FIG. 3 on thetransformer monitoring device 2400 of FIG. 23.

The transformer monitoring device 2400 comprises an extended boxlikehousing section 1012. Within the housing section 1012 resides one ormore printed circuit boards (PCB) (not shown), semiconductor chips (notshown), and/or other electronics (not shown) for performing operationsrelated to the general purpose of the monitoring device 2400. In oneembodiment, the housing section 1012 is a substantially rectangularhousing; however, differently sized, and differently shaped housings maybe used in other embodiments.

Additionally, the transformer monitoring device 2400 further comprisesone or more cables 1004, 1007. The cables 1004, 1007 may be coupled to aconductor cable or corresponding bus bars (not shown) and ground orreference voltage conductor (not shown), respectively, for thecorresponding conductor cable, which will be described further herein.Voltage readings are taken through the cables 1004 and 1007.

Note that the cables 1004, 1007 may be connected via externalweatherproof connectors as described hereinabove. When connected viaexternal weatherproof connectors, the cables 1004, 1007 may be replaced,for example if they are not working properly.

Note that methods in accordance with an embodiment of the presentdisclosure use the described transformer monitoring device 2400 forcollecting current data, voltage data, and other operational datarelated to the transformer to which the transformer monitoring device iscoupled. The transformer monitoring device 2400 further comprises atleast one sensor 2401-2403 for detecting signals, i.e., data. In oneembodiment, the transformer monitoring device 2400 collects voltage andcurrent data on a low voltage (LV) side of a transformer circuit.Further, there may be some other type of sensor (not shown) installednear the transformer monitoring device 2400 coupled to the low-voltage(LV) or medium voltage (MV) side that is configured to communicate withthe transformer monitoring device 2400. One example of a nearby sensor(not shown) on the MV side may be a fault indicator, which transmitsdata indicative of a fault on the transformer circuit. In such anembodiment, the sensor 2401 would detect the data indicative of thefault and transmit data indicative of the fault to the central computingdevice 2102, thereby alleviating the need for an operator to manuallyread the fault indicator.

Note that a fault indicator is one of numerous types of sensors that maybe used to gather data from the circuit to which the transformermonitoring device 2400 is coupled. One such method, which will bedescribed further herein, is that the transformer monitoring device maycollect data from sensors on transformer circuits up or down the powerline to which the transformer circuit is coupled from other sensors.Thus, the transformer monitoring device 2400 may further have aninterface or communications bus, either wired (including a serial port,a usb port, etc.), wireless (including a Bluetooth Wi-Fi (a trademarkrepresenting IEEE 802.11x, etc.) or optical. The transformer monitoringdevice 2400 transmits data through the interface or communication busvia the network 2408 and to the central computing device 2102.

In another embodiment, the transformer monitoring device 2400 furthercomprises at least one port 2404-2406 for wired or wireless coupling toa sensor used in the transformer circuit. Using the example above, theport 2404 may be coupled to the fault indicator via a wire (not show).The fault detector may detect a fault in the transformer circuit andtransmit data indicative of the fault over the wire to the port 2404,and the transformer monitoring device 2400 transmits data indicative ofthe fault to the central computing device 2102 either wired orwirelessly through the network 2408. The central computing device 2101alerts an operator to the fault without the operator having to manuallycheck the fault indicator.

In one embodiment, the transformer monitoring device 2400 furthercomprises a display device 2411. One such display device may be a liquidcrystal display (LCD). The display device 2411 allows user interfacewith the functionality and operation of the transformer monitoringdevice 2400

In this regard, once the transformer monitoring device 2400 is coupledto power, the display device 2411 may display data indicative of devicebooting, connecting to the network, connected to the network (with theinternet protocol (IP) address), and the like. Additionally, the displaydevice 2411 may display data indicating provisioning complete with theserver. Furthermore, the display device 2411 may indicate that thetransformer monitoring device 2400 is reading voltages and/or currents,and the display device 2411 may show the power factor. Notably, thedisplay device 2411 is configured for showing any fault conditionseither with the transformer monitoring device or in the power, voltage,current, power factor, or any operational value measured by thetransformer monitoring device 2400. This indication on the displaydevice 2411 may alert an installer to a problem with the transformercircuit, the installation, or any other alert detected by thetransformer monitoring device 2400.

Note that the transformer monitoring device 2400 may also compriseinternal sensors or probes for collecting data indicative of ambienttemperature, actual fire, ground and/or surface temperature, vibration,smoke, nuclear radiation, noxious gases, humidity, external transformertemperature, and geo-positioning. In such a scenario, if one of themonitored characteristics indicates a problem the transformer monitoringdevice 1000 is configured to notify utility personnel or anotherindividual in charge of emergency situations. In such an embodiment, thedisplay device 2411 may display data indicative of ambient temperature,ground and/or surface temperature, vibration, smoke, nuclear radiation,noxious gases, and geo-positioning.

Notably, any fault conditions either with the transformer monitoringdevice 2400 or in the power, voltage, current, power factor, or anyparameter measured by the device would show an indication on the displayto advise the installer and/or user of the condition.

In one embodiment, the display device 2411 may display operationalvalues. For example, the display device 2411 may display kWh consumptionin a similar way to an AMI meter.

The system 2407 may further comprise a portable device 2412 configuredto communicate with the communication interface of the transformermonitoring device 2400. The portable device 2412 may be, for example, aSmartphone with a controlling application, a laptop personal computerwith custom software, or a custom device provided by the company.

The portable device 2412 may be used to communicate with the transformermonitoring device 2400 for the purposes of configuration of thetransformer monitoring device 2400, viewing live data such as power,voltage, current, power factor, etc., and to download historical datathat may be stored in the memory of the transformer monitoring device2400. The user terminal would also assist in connecting to the CellularData Network, Mesh RF Network, RF LAN, Satellite, or other network asappropriate by helping an installer determine if the transformermonitoring device 2400 is experiencing an acceptable network connection.

Further, a fire may be detected by the transformer monitoring device2400. In such a scenario, the transformer monitoring device transmits awarning to the portable device 2412. The warning indicates that a fireor fire-like conditions has been detected by the transformer monitoringdevice 2400.

FIG. 24 shows a system 2707 that comprises another embodiment of atransformer monitoring device 2700. The system 2707 further comprisesthe central computing device 2101 that is communicatively coupled to thetransformer monitoring device 2700 via the network 2408.

The polyphase distribution transformer monitor (PDTM) 2700 in accordancewith an embodiment of the present disclosure is substantially like PDTM1400 shown regarding FIG. 14. Thus, for purposes of this disclosure,polyphase refers to a system for distributing alternating currentelectrical power and has two or more electrical conductors wherein eachcarry alternating currents having time offsets one from the others. Notethat while the PDTM 2700 is configured to monitor four conductors, thePDTM may be used to monitor one or more conductors, e.g., single phaseor two-phase power, which is substantially like monitoring three-phasepower, which is described further herein.

The PDTM 2700 comprises the control box 1498, which is a housing thatconceals a plurality of electronic components, discussed further above,that control the PDTM 2700. Additionally, the PDTM comprises a pluralityof satellite current sensors 1490-1493.

The satellite current sensors 1490-1493 are structurally andfunctionally substantially like the satellite unit 1021 describedregarding FIGS. 3; 7, and 8. In this regard, the satellite currentsensors 1490-1493 detect a current through an electrical cable, bus bar,or any other type of node through which current passes into and/or froma distribution transformer.

During operation, one or more of the satellite current sensors 1490-1493is installed about conductor(s) (e.g., cables), bus bars, or other typeof node through which current travels. In addition, each of the ringterminals 1476-1479, respectively, are coupled to the conductor, busbar, or other type of node around which their respective satellitecurrent sensor 1490-1493 is installed.

More specifically, each satellite current sensor 1490-1493 takes currentmeasurements over time of current that is flowing through the conductorcable, bus bar, or node around which it is installed. Also, over time,voltage measurements are sensed via each of the satellite currentsensor's respective voltage cables 1484-1487. As will be describedherein, the current measurements and voltage measurements taken overtime are correlated and thus used to determine power usage correspondingto the conductor cable, bus bar, or node.

The PDTM 2700 further comprises a set of sensors 2701-2703. The sensorsmay be any type of sensor known in the art or future developed. Thesensors 2701-2703 are configured to communicate with a sensor containedin a transformer circuit to which the PDTM is coupled. Note that threesensors are shown, but the PDM can comprise more or fewer sensors inother embodiments. These sensors may be infra-red sensors, probes,thermocouples, gyroscopes, tilt sensors, transducers, or the like.

The PDTM 2700 further comprises a communication interface. For example,the communication interface may be a Wi-Fi interface.

Upon detection of operational data associated with the transformercircuit by the sensors 2701-2703, the PDTM, via its communicationinterface, is configured to transmit data indicative of the detectedoperational data to the central computing device 2102. Thus, an operatorat the location of the central computing device 2102 may be alerted tothe operational data, including a change in the transformer circuitwithout the need for manually inspecting the transformer circuit towhich the PDTM 2700 is coupled. Note that above, a fault sensor is givenas an exemplary device that may detect a fault, transmit data of thedetected fault to one of the sensors, and the communication interfacetransmits data indicative of the detected fault to the central computingdevice 2102.

The system 2707 additionally comprises ports 2704-2706, like thosedescribed in FIG. 23. The ports 2704-2706 may be physically wired to asensor. The ports 2704-2706 receive data indicative of operational dataof the transformer circuit to which the PDTM is coupled and thecommunication interface transmits the operational data to the centralcomputing device 2102 via the network 2408.

In one embodiment, the transformer monitoring device 2700 furthercomprises a display device 2750. One such display device may be a liquidcrystal display (LCD). The display device 2750 allows user interfacewith the functionality and operation of the transformer monitoringdevice 2700.

In this regard, once the transformer monitoring device 2700 is coupledto power, the display device 2750 may display data indicative of devicebooting, connecting to the network, connected to the network (with theinternet protocol (IP) address), and the like. Additionally, the displaydevice 2750 may data indicate provisioning with the server, that thetransformer monitoring device 2700 is reading voltages and/or currents,and the display shows the power factor. Notably, the display device 2750is configured for showing any fault conditions either with thetransformer monitoring device or in the power, voltage, current, powerfactor, or any operational value measured by the transformer monitoringdevice 2700. This indication on the display device 2750 may alert aninstaller to a problem with the transformer circuit, the installation,or any other alert condition associated with the transformer monitoringdevice 2700.

In one embodiment, the display device 2750 may display operationalvalues. For example, the display device 2750 may display kWh consumptionin a similar way to an AMI meter.

Note that the following description describes functionality andarchitecture that may be attributed to both the system 2407 and thesystem 2707. Thus, hereinafter in the description the terms DTM 2400 andPDTM 2700 are collectively referred to as “Transformer MonitoringDevices.” Further, portable device 2412 is collectively referred to as“Portable Devices.” Also, the central computing devices 2102 arecollectively referred to as “Central Computing Devices.” Additionally,sensors 2401-2403 and 2701-2706 are collectively referred to as “SensorDevices” and ports 2404-2406 and ports 2704-2706 are collectivelyreferred to as “Ports.” Also, networks 2408 are referred to as“Networks.”

Through the Portable Devices, a user may configure the TransformerMonitoring Devices, view real-time data (e.g., power, voltage, current,power factor, etc.), and/or download historical data that may be storedin memory of the Transformer Monitoring Devices.

In another embodiment, each of the Portable Devices is furtherconfigured with a communication interface to assist in connecting to acellular data network, mesh radio frequency (RF) network, RF local areanetwork (LAN), or any other type of network, as appropriate. By usingthe described networks an installer of the Transformer MonitoringDevices can determine if the Transformer Monitoring Devices areexperiencing an acceptable network condition.

In one embodiment, a utility may utilize wireless mesh networks toimplement their automatic meter reading (AMR) and/or advanced meteringinfrastructure (AMI) networks. Many of these types of networks rely on ahigh density of meter devices or network repeaters to improve networkintegrity and capability.

The Transformer Monitoring Devices are configured to increase thedensity of the mesh network devices by repeating signals received, i.e.,behaving as a network repeater. Additionally, Transformer MonitoringDevices allow the utility to monitor the distribution transformer datasimultaneously. A Transformer Monitoring Device would help increase thedensity of mesh network devices and perform virtually the same functionas a network repeater but would also bring the capability to the utilityto monitor the distribution transformer data simultaneously. Also, manynetwork repeater devices that AMR/AMI vendors provide are expensive anddifficult to install. Transformer Monitoring Devices would cost less inmost cases and install in a few minutes. And given that many TransformerMonitoring Devices are mounted on poles that are 25+ feet above theground, they serve as good repeaters for many mesh networks.

Where a utility has an AMR network that requires sending meter readersinto the field who physically drive to locations nearby the electricmeters to read them via a short range wireless network, the TransformerMonitoring Devices may replace these drive-by readings by implementingthe same wireless network function ability and then back-hauling themeter reading data over the associated wide area network (WAN) that theTransformer Monitoring Devices use. As a mere example, a cellularTransformer Monitoring Device would take meter readings via the AMRnetwork's native short range RF technology and then upload that meterdata to the Central Computing Devices via WAN technology.

In one embodiment, Transformer Monitoring Devices may comprise aneighborhood area network (NAN) wireless mesh for communications. Insuch scenario, the Transformer Monitoring Devices serve as a bridge tothat network to backhaul the data via the WAN connection, such as acellular data network, a Wi-Fi connection to a broadband internetconnection, etc.

In one embodiment, one of the Ports is a fiber optic port. The fiberoptic port allows direct connection to utility-owned fiber opticnetworks. Because fiber does not conduct electricity, there is limitedsafety risks. In such a scenario, the Transformer Monitoring Devices areprogrammed to communicate via the fiber optic network to a plurality ofnetwork destinations such as the Central Computing Devices or any otherserver to which the Transformer Monitoring Devices are communicativelycoupled. Utility customers would also have the benefit of directlyintegrating the Transformer Monitoring Devices with the sensors directlyin their Supervisory Control and Data Acquisition (SCADA) systems orother monitoring and control systems.

In one embodiment, Transformer Monitoring Devices monitor operationalvalues such as harmonics, transients, sags, swells, voltage and currentspikes, noise, etc., via their respective Sensors. A user of the CentralComputing Devices with access to the Transformer Monitoring Devices, viathe Networks, can set thresholds to trigger automated alerts when thethresholds are met or exceeded. The Transformer Monitoring Devices keepa sliding window, e.g., for a predetermined period, of real-time valuesto report with the automated alert. As an example, a user would set athreshold on total harmonic distortion (THD) a value. When theTransformer Monitoring Devices detect that the threshold value has beenmet or exceeded, the Monitoring Devices access the last thirty secondsof real-time waveform data collected, append to it the next 30 secondsof real-time waveform data, and upload data to the Central ComputingDevices for presentation to the user. In response, the user can view thetransformer behavior before and after the THD event to determine thecause of the THD event.

In one embodiment, one of the Ports may be coupled to a device fordownloading user-defined software, firmware, or the like to theTransformer Monitoring Devices. In this regard, a customer, or serviceprovider could write custom logic programs that would enhance theTransformer Monitoring Devices' performance. As a mere example, a scriptof the software or firmware may read (MAX_CURRENT>AVG_CURRENT*1.5) AND(MIN_VOLTAGE*0.95) THEN_ALERT “Transformer is undersized.” The user ofthe central computing device 2102 may receive this data and takes stepsto remedy the issue without physically going to the transformer. In oneembodiment, the current sensor of the Transformer Monitoring Device maycomprise sharpened “teeth.” The teeth may be configured to pierce intothe conductor that passes through the sensor and contact the underlyingwire to sense voltage at the conductor.

In one embodiment, the Transformer Monitoring Devices are configured toproduce customizable, automated alerts to end users (e.g., user of theCentral Computing Devices, user of a portable device, text messages toutility personnel, etc.). These automated alerts are configured based onspecific operational values either exceeding thresholds (maximum andminimum values), delta values (this operational value changed more thanX amount since the last time it was reported, etc.), variance (thisvalue is more than Y standard deviations from its average over time orfor this time of the day), trigger (this operational value hits aspecific value), or time-based (this operational value has been X for atime). Types of data that may be automatically monitored include rootmean square (RMS) voltage both overall and per phase, RMS current bothoverall and per phase, Kilovolt ampere rating (KVA) and kilovolt amperereactance (KVAR), power factor (overall and per phase), voltageimbalance, harmonic distortion (overall and per phase), sags, swells,line power loss and line power restored (overall and per phase, coupledwith geographic information systems (GIS) data can automatically betransmitted to the Central Computing Devices with the addition of GISinformation to show location of the line break/fault), and line fault.Note that as described above, the Transformer Monitoring Devices areconfigured to monitor a plurality of distribution transformers along apower grid line via wireless communication. In such an embodiment, thedata transmitted to the Transformer Monitoring Devices may include dataindicative of a transformer identifier or the GIS information so that auser can determine which transformer is experiencing issues.

When an alert activates, the Transformer Monitoring Devices transmitdata indicative of the alert in real-time. The data is transmitted tothe assigned system on the WAN and is processed and routed perprogrammed recipients and rules. As an example, the rule may designatethe Central Computing Devices or the Portable Devices that are used byan operator in the field receive event data. In this way, the user ofthe Central Computing Devices or the operator of the Portable Devicesmay respond immediately to the alert.

In one embodiment, Transformer Monitoring Devices accurately compare thepower recorded by downstream transformers. In such a scenario, it isimpossible to detect all types of secondary power loss, and thereforeaccurately measures the amount of power for which the utility is notbeing paid by consumers. One way to stop theft power loss is to createreconciliation points at the distribution transformer to which theTransformer Monitoring Devices are coupled. This is accomplished byproperly identifying power being delivered to downstream meters. Thereconciliation device may be one or more of the Transformer MonitoringDevices that receive downstream power data and compare the powersupplied downstream with the power used downstream. Thus, theTransformer Monitoring Devices can effectively address a power theftevent or a mismatch of transformers to meters.

In this regard, Transformer Monitoring Devices not only collect loss ofpower data from the distribution transformer to which it is coupled. Italso collects upstream and downstream data, which can be used toaccurately sum the power losses to determine theft of power or amismatch of transformers to meters.

As an example, a customer may set up a bypass for their air conditioning(A/C) system so that it doesn't register with the house meter, i.e., thepower cable does not run through the meter so the power used is notdetected and cumulated with the power used by the customer. When thecustomer has free (A/C), they crank the thermostat down several degrees.Measurements indicate that for every 2 degrees a set point is lowered,and the AC may take 10% more energy to maintain that temperature. Theutility AMI system detects that this customer does not have the sameload profile on hot summer days since last year and seeks restitutionfor the theft. When the Transformer Monitoring Devices are coupled tothe distribution transformer, the Transformer Monitoring Devices providethe exact amount of stolen power that is measured and not estimated.

In one embodiment, the Transformer Monitoring Devices communicatethrough next generation 4G networks with bandwidth capacity able toexceed 100 megabytes per second. Due to this extraordinary bandwidth andreal-time capability, detailed data can be transmitted from theTransformer Monitoring Devices to the Central Computing Devices. In sucha scenario, the Transformer Monitoring Devices can transmit waveformdata to the user, which the user can use to remotely monitor thebehavior of the distribution transformer. While streaming this type ofdata for protracted periods of time may be costly, the costs pale incomparison to the cost of rolling a truck to the site of thedistribution transformer to collect the same detail of data. In such ascenario, compression and decompression tools may be used to allow evengreater amounts of data to be processed and displayed for optimizedcost.

The Central Computing Devices are configured to receive the detaileddata from the Transformer Monitoring Devices. Further, the CentralComputing Devices are configured to provide a virtual digitaloscilloscope interface to analyze the performance of the distributiontransformer in real-time, set triggers on various events, and captureraw digital values for trace analytics to decipher.

In one embodiment, by placement of the Transformer Monitoring Devicesthroughout a power grid, wherein the Transformer Monitoring Devices haveGPS capability, such placement enables a Central Computing Device togenerate a map of all Transformer Monitoring Devices in a general area.In this regard, if the Transformer Monitoring Devices are presented withthe accurate AMI/AMR meter data assigned to a specific distributiontransformer, the Transformer Monitoring Devices are configured to verifythe correct mapping association of meters to transformers, or uncoversthe mapping errors within the utility's system. Also, the TransformerMonitoring Devices reveal that there is some form of unmetered loss orunmetered DER/DG occurring at a given distribution transformer.

Adding an electric vehicle (EV) charging station, electric point-of-usewater heater, high speed electric over or other significant load to ahome or business is becoming commonplace. Adding such loads to anexisting transformer places an unexpected and unplanned load on thetransformer that could affect both the efficiency and the lifeexpectancy of the asset. Without AMI/AMR systems and advanced analytics,the utility may be unaware that the distribution transformer isexperiencing overloading situations from these added loads. TheTransformer Monitoring Devices monitor the load at the distributiontransformer so that it can accurately show a user of the CentralComputing Devices or a user of the Portable Devices data indicative ofthe unaccepted load.

In one embodiment, the Transformer Monitoring Devices are configured todetect a transition from positive power (power flowing from the grid toresidential or commercial end users) to negative power (power flowinginto the grid from distributed generation (DG) energy models and frompower flowing into the grid from distributed energy resources (DER). ADER energy model for purposes of the present application is asmall-scale power generation source located close to where electricityis used (e.g., a home or business), which provides an alternative to oran enhancement of the traditional electric power grid. Such powerresources can be, for example, wind turbines or photovoltaic solarpanels. The DG energy model for purposes of this application is powergeneration at the point of consumption by generating power on-site,which eliminates the cost, complexity, interdependencies, andinefficiencies associated with transmission and distribution of energy.

The DG/DER energy models make this ongoing/daily transition (frompositive power to negative power), for example as the sun sets in theevening, the grid control systems and power maintenance subsystems mustbe prepared to activate power delivery while reserving DG and reserveassets that come online. A distribution network with a full deploymentof Transformer Monitoring Devices can provide, via transmitting anautomated alert to the Central Computing Devices or the PortableDevices, the information needed to accurately determine when and howmuch power must be brought online to compensate for the decrease/loss ofDER/DG energy being driven up into the grid. In response, the operatorof the Portable Device or a user of the Central Computing Device cantake steps to ensure that during the transition, power needed or notneeded is effectively provided to ensure proper continuous powerdelivery by the grid.

Note that the life expectancy of a distribution transformer can besignificantly affected by the loads that the transformer bares over alifetime. Pushing a distribution transformer past its rated capacity canreduce the life expectancy of this critical grid asset. In such anembodiment, the Transformer Monitoring Devices provide accurate,time-based measurements of transformer loading that can feed intomathematical models at the Central Computing Devices to calculate thelife expectancy based upon the load profile the distribution transformerexperiences. This load profile is generated by the data transmitted tothe Central Computing Devices from the Transformer Monitoring Devices.

Note that balancing the load across all three phases on an electricaldistribution feeder circuit can drastically affect the efficiency of thedistribution grid. Also, unbalanced loading of a feeder can stress gridassets (e.g., distribution transformers) and could potentially causevoltage imbalances and circuit failure. In such a scenario, TransformerMonitoring Devices coupled to distribution transformers are connected tothe distribution grid with no regard for which phase to which theTransformer Monitoring Device is coupled. For example, in emergencypower restoration scenarios, like one that would occur during a majorstorm, priority is placed on speed of reconnection and not on loadbalancing.

In such a scenario, the Transformer Monitoring Devices determines towhat phase a single-phase distribution transformer is connected and thecumulative loads on that feeder. With highly accurate clocks set bysub-millisecond times servers such as a global positioning system (GPS)clocks, the Transformer Monitoring Devices can take measurements of theAC voltage line cycle zero crossing and work in concert with otherTransformer Monitoring Devices, which is described above, to determinewhich Transformer Monitoring Devices are connected to which phase ofeach Transformer Monitoring Device.

Note that distribution transformers have a capability known as tapsetting that allows the distribution transformer to be configured forslight variances in the primary voltage along the feeder. These tapsettings adjust the secondary voltage slightly up or down to present thecorrect voltage range to the end customers. Setting the tap setting tothe wrong value results in extremely high or exceptionally low voltagebeing supplied to the home or business and could cause damage toelectrical equipment and systems at those locations.

The Transformer Monitoring Devices provide data that allows a utilityengineer to locate distribution transformers that do not have theirvoltage tap settings adjusted to the proper values. In this regard,Transformer Monitoring Devices upstream or downstream from theTransformer Monitoring Devices receive data indicative of tap settings,compares the tap settings to an effective tap setting, and alerts thePortable Devices or the Central Computing Devices of the comparison.Note that a distribution transformer that lies outside of the “group”usually indicates an invalid tap setting.

Weather is one of the most important factors that affect the electricalgrid. Temperature increases and decreases trigger heating ventilationand cooling (HVAC) systems to operate activate and/or deactivate. Insuch a scenario, the Transformer Monitoring Devices, because theycommunicate over some form of wide area network that could cover autility's entire distribution grid space, offer a Transformer MonitoringDevices in a network that communicate weather data back that would notjust represent the overall weather at a city or county level, but thespecific weather at a given location.

In such a scenario, the Transformer Monitoring Devices comprise anintegral weather Sensor such as temperature and humidity sensors. Datafrom the Sensors communicate over a wireless network to weather stationsproviding access by the Transformer Monitoring Devices with a full arrayof weather data. Utilities could purchase and install inexpensivewireless weather sensor packages and the Transformer Monitoring Devicesreport the weather data to the Central Computing Devices. In response, auser of the Central Computing Devices may take steps to ensure thevitality of the power grid based upon the weather data received from theTransformer Monitoring Devices.

In one embodiment, one of the Sensors may be a vibration sensor todetect movement or vibration. Detection of movement may indicatepotential tampering or a catastrophic failure, such as a broken utilitypole. The Transformer Monitoring Device may comprise threshold vibrationdata, and if the vibration detected by the Sensor meets or exceeds thethreshold, the Transformer Monitoring Devices can report data indicativeof vibration to the Portable Devices or the Central Computing Device sothat proper action may be taken to ensure against complete failure of adistribution transformer.

In another embodiment of the Transformer Monitoring Devices a Sensor maydetect sound. Note that the sound of a distribution transformer canindicate the health of the distribution transformer. In this regard,most distribution transformers create a small hum during operation. Anincrease in the volume of the hum may indicate that the load on thedistribution transformer has increased. However, excessive noise,boiling sounds, loud bangs, etc. can indicate that the distributiontransformer has a serious problem.

The Transformer Monitoring Devices can use the audio Sensor to recordsounds. The Transformer Monitoring Device may compare the sounds to apre-determined sound data indicating a sound threshold. Thus, if thecomparison indicates a problem, the Transformer Monitoring Devicestransmit data indicative of the sounds or a simple sound alert to theCentral Computing Devices or the Portable Devices, so that the problemmay be remedied prior to a failure of the distribution transformer.

In one embodiment, the Transformer Monitoring Devices may stream thedata to the Portable Devices or the Central Computing Devices. Thus, auser or operator can hear the actual sound occurring at the distributiontransformer. Note that other sounds may be detected by the audio Sensorthat indicates, for example, gunshots, which could also trigger an alertor event.

Note that distribution transformers are filled with oil to maintaincooling and help with the electrolytic properties of the distributiontransformer. However, when the oil leaks out, not only does this createa situation that can affect the operation of the distributiontransformer, but the leak can also have an environmental impact.

In one embodiment, the Transformer Monitoring Devices comprise a vaporSensor. The vapor sensor detects the presence of the oils used in thedistribution transformer. The Monitoring Device compares the dataretrieved by the sensor to a threshold value. If the data meets orexceeds the threshold value, the Transformer Monitoring Devices transmitdata indicative of an alert related to the excess vapor to the PortableDevices or the Central Computing Device so that personnel can be sent tothe transformer for inspection.

In one embodiment, the Transformer Monitoring Devices comprise Sensorsfor detecting tampering. In this regard, the Sensors may detect motionindicating that the Transformer Monitoring Devices have been moved. Inaddition, the Sensors may detect that the current sensors have beenunlocked and opened to remove the Transformer Monitoring Devices fromthe distribution transformer. The Sensors may also detect that the unithas been unsealed and/or opened or that an external device has beenintroduced to the conductors to shield the current signature in someway.

Upon detection of any of the foregoing, the Transformer MonitoringDevices may transmit data to the Portable Devices or the CentralComputing Device. Utility personnel may then be sent to the physicaldistribution transformer to determine the problem.

The Transformer Monitoring Devices further have a global positioningsystem (GPS). The GPS records data indicative of the exact location ofthe Transformer Monitoring Devices on the planet. In one embodiment, thelocation data may be transmitted to the Central Computing Device uponrequest or periodically. The Central Computing Device compares thelocation data with the utility's GIS data to ensure that align properlywith the expected location of the transformer.

In normal operation, the Transformer Monitoring Devices and CentralComputing Devices associated with the Transformer Monitoring Devicesthat calculate the energy balance equations consider the energy used bystreetlights. The streetlights come on at dusk and go off at dawn. Mostpublic streetlights are not metered, and many public utilities areresponsible for the maintenance of the streetlights. Often lamps blowout and light sensors fail resulting in darkness at night and lightsburning during the daylight hours.

In one embodiment, the Transformer Monitoring Devices align theunbalanced energy with the times the streetlights should be on. In thisregard, the Transformer Monitoring Devices can determine that there isno power being consumed when it should be (the light is out) or there ispower being consumed when it should not be (the photocell is broken).Upon determination of either scenario, the Transformer MonitoringDevices transmit data indicative of the scenario to the Portable Devicesor the Central Computing Devices so that personnel may be directed tothe malfunctioning streetlight. Notably, determination of the locationof the streetlight may be aided by the GPS described above.

As described above, DER/DG monitoring are becoming more prevalent on thegrid every day. From solar panels to battery banks, the complexity ofdevices and systems that may be injecting power into the grid is quicklybecoming unwieldly. The Transformer Monitoring Devices, as describedabove, can monitor whether the flow of energy at a distributiontransformer is positive or negative and indicate the amount of energybeing injected. Such data may be transmitted to the Central ComputingDevice, and the data may be used by the operator to determine at whatlocation an additional distribution transformer may be necessary byidentifying the transformers with the larger reverse power flows.

When a single polyphase transformer supplies power to multiple homes andbusinesses, the distribution transformer can become unbalanced. In sucha scenario, one or two phases are supplying much more energy than theothers. When unbalanced, a distribution transformer is inefficient, andthe unbalanced nature can affect the life expectancy of the distributiontransformer is severe.

In one embodiment, the Transformer Monitoring Devices can detect whenone or two phases are outputting more energy than the others. In thisregard, the Transformer Monitoring Devices take every sample and computethe imbalance percentage periodically and track high and averageimbalance measurements. At times of high imbalance, the TransformerMonitoring Devices can transmit data indicative of the imbalance so thatcorrective measures may be taken by the Utility.

In one embodiment, the Transformer Monitoring Devices monitor energy andvoltage along a feeder. Additionally, the Central Computing Devices maytransmit data to the Transformer Monitoring Devices a calculation ofline-feet from the substation. The Transformer Monitoring Devices cancalculate measurements for the line loss to accurately depict the lossesthat occur as the distance from the substation increases.

Voltage Optimization (VO) is the practice of using advanced voltageregulators on the grid to keep voltage at the minimum level that stillprovides acceptable voltage to consumers. Conservation Voltage Reduction(CVR) is the practice of lowering system voltages in response to peakdemand or other situations that require the overall system demand to belowered. To have an effective VO/CVR system, operating voltage ismonitored along the feeder to ensure that minimum voltage limits aremaintained. Many utilities do not have AMI networks deployed that couldprovide the near real-time feedback for an effective advanced voltageoptimization control scheme.

In one embodiment of the present disclosure, the Transformer MonitoringDevices accurately measure secondary voltage at the distributiontransformers throughout the grid. Thus, the voltage values measured bythe Transformer Monitoring Devices may be used by the Central ComputingDevices to keep voltage at a minimum level while still providingacceptable voltage to consumers. Also, the voltage values measured bythe Transformer Monitoring Devices may be used to by the CentralComputing Devices to lower voltages in response to peak demand or othersituations that require the overall system demand to be lowered.

State estimation combines knowledge of system topology and steady-statebehavior, i.e. voltages and currents of real and reactive power flows.The objective of state estimation is to identify the steady-statevoltage magnitudes and angles at each bus in a network, which completelycharacterizes the operating state of the system, meaning the real andreactive power flows on every link, as well as power injected into orwithdrawn from each bus.

State estimation for distribution systems is substantially moredifficult than in transmission. However, if distribution systems are tobe thoroughly understood and actively managed, knowledge of thesteady-state operating condition in real-time is a precondition forinterpreting specific information about devices or incident. It is alsoa precondition toto informing control actions aimed at optimizing thebehavior of the system.

In one embodiment of the present disclosure, the Transformer MonitoringDevices are installed on each of the distribution transformer on afeeder. The Transformer Monitoring Devices are configured to allowaccurate state estimations by estimating voltage magnitude and angle atevery bus for a distribution transformer circuit because thedistribution transformers effectively constitute a bus.

FIG. 25 is a circuit diagram depicting a transformer circuit 2900 inaccordance with an embodiment of the present disclosure. The transformercircuit 290 comprises a primary winding 2902 on the medium or highvoltage side of the transformer circuit 2900. Further, the transformercircuit comprises a secondary winding 2903 on the low voltage side ofthe transformer circuit 2900.

A fault indicator 2904 is coupled to a medium or high voltage side ofthe transformer circuit 2900. Additionally, the transformer monitoringdevice 2400, described with reference to FIG. 23, is coupled to a lowvoltage side of the transformer circuit 2900.

Note that the fault indicator 2904 is any type of electrical device thatcan detect current or voltage through the primary winding 2902. Furthernote that in the embodiment depicted in FIG. 28, the fault indicator2902 is configured to transmit data indicative of a fault through themedium or high voltage side of the transformer circuit 2900.

In operation, the fault sensor 2904 is configured detect a high currentpassing through a conductor on the high voltage side of a transformer.Thus, if the fault indicator 2904 detects a high current through themedium or high voltage side of the transformer circuit 2900, the faultindicator 2904 transmits data indicative of the fault to the transformermonitoring device 2400.

As described hereinabove, the transformer monitoring device 2400 maydetermine, based upon the data received from the fault indicator 2904,to send data indicative of the fault to the central computing device2102 (FIG. 23). Upon receipt, the central computing device 2102 (FIG.23) may determine that a notification is warranted, determine to whom tosend the notification, and when to send the notification.

Note that in one embodiment, the transformer monitoring device 2400 mayalso be configured with a communication interface 2050 (FIG. 5). In suchan embodiment, the transformer monitoring device 2400 may be configuredto transmit data indicative of the fault to the portable device 2412.

FIG. 26 is a system 2600 that comprises power lines 2607 that deliverpower to transformer 2601 and up the line to transformer 2602 andtransformer 2603. On each transformer 2601-2603, a transformermonitoring device 2400 or 2700 is installed on a low voltage side ofeach transformer 2601-2603. Further, on each transformer 2601-2603 isinstalled a sensor 2605-2606. Note that the sensors 2604-2606 may beconfigured to detect operational data associated with the transformers2601-2603, respectively.

In one embodiment, the transformer monitoring devices 2400 or 2700comprises a communication interface that communicatively couples thetransformer monitoring devices 2400 and 2700. In one embodiment, thecommunication interface is a Wi-Fi interface for receiving andtransmitting data, which is described above.

In operation, the sensors 2605 and 2606 are monitoring any type ofoperational data related to the transformer 2602 and transformer 2603,respectively. If an event occurs, for example an event that effectsoperation of the transformers 2602 or 2603, the respective transformermonitoring devices 2400 or 2700 transmit data indicative of the eventwirelessly to the transformer monitoring device 2400 and 2700 coupled tothe transformer 2601. In turn, the transformer monitoring devices 2400or 2700 determine whether to transmit the data to the central computingdevice 2012 (FIGS. 23 and 24) or central computing device 2102 (FIGS. 23and 24).

FIG. 27 depicts another system 3010 in accordance with an embodiment ofthe present disclosure. The system 3010 comprises a plurality of meters3000-3005 for metering power used at customer premises (not shown).

The system 3010 comprises an automated metering infrastructure (AMI)mesh collector 3007. The mesh collector 3007 collects data from themeters 3000-3001. In the embodiment shown, the system 3010 furthercomprises a radio frequency (RF) mesh repeater 3008. In a typical AMImesh system, data is obtained from meters, e.g., 3003 and 3002, and thedata collected is transmitted to the AMI mesh collector.

In one embodiment, the system 3010 comprises a DTM 2400 or a PDTM 2700.The DTM 2400 or PDTM 2700 collects data from meters 3005 and 3004. Insuch a scenario, the DTM 2400 or the PDTM 2700 is configured as arepeater like the RF mesh repeater 3008. Thus, the DTM 2400 or the PDTM2700 can transmit data collected to the AMI mesh collector 2700.

In one embodiment, the voltage connector terminators areinterchangeable. In this regard, FIGS. 28A, 28B, 28C, and 28C allrepresent different terminators for voltage cables. Notably, FIG. 28A isan alligator clip that could be used to couple a voltage lead with anode. FIG. 29B is a piercing connector, FIG. 28C is a ring terminal, andFIG. 28D is a spade terminal. Any of these interchangeable connectorsmay be used to coupled voltage cables to the distribution transformer.

Additionally, voltage cables could be offered in various lengths alongwith the variety of termination types. Also, since different countriesand even different areas of a country tend to use different colorschemes for polyphase circuit identification. These interchangeablevoltage leads are offered with a variety of color bands installed sothat the appropriate colors can be used for the local utility toproperly identify the multiple phases for proper installation of theTransformer Monitoring Devices.

What is claimed is:
 1. A monitoring device, comprising: one or morevoltage sensors integral with a housing for detecting a voltage of apower cable of a transformer; one or more environmental sensorsincluding a smoke sensor configured to detect smoke in an areasurrounding the transformer; a processor configured to monitor the smokesensor, the processor configured to transmit a message if smoke isdetected surrounding the transformer.
 2. The monitoring device of claim1, wherein one of the environmental sensors is an ambient temperaturesensor.
 3. The monitoring device of claim 2, wherein one of theenvironmental sensors monitors ambient temperature, and if the ambienttemperature nearby the transformer rises to a detrimental level thatindicates a fire or fire-like condition surrounding the transformer, theprocessor is configured for notifying personnel of the fire or potentialfire condition.
 4. The monitoring device of claim 1, wherein one of theenvironmental sensors monitors actual fire, ground and/or surfacetemperature, and if the actual fire ground and/or surface temperature ofthe transformer rises to a detrimental level indicating a fire orfire-like condition surrounding the transformer, the processor isconfigured for notifying personnel of the fire or potential firecondition.
 5. The monitoring device of claim 1, wherein one of theenvironmental sensors monitors nuclear radiation, and if there isnuclear radiation present, the processor is configured for notifyingpersonnel of the nuclear radiation.
 6. The monitoring device of claim 1,wherein one of the environmental sensors monitors noxious gases, and ifthere are noxious gases present, the processor is configured fornotifying personnel of the noxious gases.
 7. The monitoring device ofclaim 1, wherein the one or more environmental sensors is directlycoupled to the transformer monitoring device.
 8. The device of claim 1,wherein the one or more environmental sensors is external to thetransformer monitoring device and is communicatively coupled to thetransformer monitoring device.
 9. A monitoring system, comprising: oneor more voltage sensors configured for detecting a voltage of a powercable of a transformer; a processor configured to monitor the voltagesensors to ensure that the transformer and/or nearby power grid assetsare operating properly, determine if a detrimental scenario is takingplace based on the monitoring, and notifying personnel of thedetrimental scenario.
 10. The monitoring system of claim 9, furthercomprising wired or wirelessly connected external sensors to aninterface or communication bus.
 11. The monitoring system of claim 10,wherein the interface or communication bus is a serial port, universalserial bus (USB) port, Bluetooth, or wireless fidelity (Wi-Fi).
 12. Themonitoring system of claim 11, further comprising the external sensorsconnected via the interface or communication bus and configured totransmit environmental data.
 13. The monitoring system of claim 12,wherein the processor is further configured for processing theenvironmental data to determine if an alert should be sent.
 14. Themonitoring system of claim 9, wherein the voltage sensors are detachableand replaceable.
 15. The monitoring system of claim 9, furthercomprising a local wireless network interface for coupling with asmartphone via an application, a laptop personal computer via customsoftware, or a custom device.
 16. The monitoring system of claim 9,further configured as a network repeater and transformer monitor and/orenvironmental monitor simultaneously.
 17. The monitoring system of claim9, further comprising a wireless network device and configured forback-hauling meter-reading data over an associated wireless area network(WAN) and uploading the meter-reading data to a server for analysis. 18.The monitoring system of claim 9, further communicatively coupled to aneighborhood area network (NAN) wireless mesh, and the processor isconfigured for serving as a bridge to the NAN to backhaul transformerdata via a wireless area network (WAN) connection like a cellular datanetwork or a wireless fidelity (Wi-Fi) connection to a broadbandinternet connection, and the processor is further configured to routedata from the WAN to one or more NAN devices on the NAN mesh or routedata from the NAN devices to the WAN.
 19. The monitoring system of claim9, further comprising a fiber optic port and configured to connectdirectly to utility-owned fiber optic networks or other fiber opticnetworks.
 20. The monitoring system of claim 9, wherein the processor isfurther configured to communicate via fiber optic network to a pluralityof network destinations of servers and data collectors.
 21. Themonitoring system of claim 9, wherein the processor is configured formonitoring harmonics, transients, sags, swells, flickers, voltage andcurrent spikes, noise, or other operational parameters, and/orsurrounding environmental conditions.
 22. The monitoring system of claim21, wherein the processor is configured for enabling a user to programand/or reprogram thresholds.
 23. The monitoring system of claim 22,wherein the processor is configured to trigger automated alerts when thethresholds are exceeded.
 24. The monitoring system of claim 9, whereincustomized programming is downloadable to the processor for execution.25. The monitoring system of claim 9, further configured for monitoringparameters that exceed thresholds, change a particular amount, vary by aspecific amount, hits a specific value, or time-based.
 26. Themonitoring system of claim 25, wherein the parameters monitored includeroot mean square (RMS) voltage both overall and per phase, RMS currentboth overall and per phase, power both overall and per phase and bothforward and reverse, power factor both overall and per phase, voltageimbalance, harmonic distortion both overall and per phase, sags, swells,line power loss and line power restored both overall and per phase, andline fault.
 27. The monitoring system of claim 26, wherein the processoris configured for alerting personnel by transmitting data indicative ofthe parameter to an assigned system on a wide area network (WAN), whichare processed and routed according to programmed recipients and rules.28. The transformer monitoring system of claim 9, wherein thetransformer monitoring device is a reconciliation device that measuresan exact amount of power that is supplied on a secondary and compareswith power recorded by downstream meters to detect all types ofsecondary power loss.
 29. The monitoring system of claim 9, wherein theprocessor is further configured for verifying a correct mappingassociation of meters to transformers or uncovering mapping errorswithin a utility's system.
 30. The monitoring system of claim 29,wherein the processor is further configured to determine unmetered lossor unmetered distributed energy resources (DER) and/or distributedgeneration (DG) occurring at the transformer.
 31. The monitoring systemof claim 9, wherein the processor is further configured for providing,via automated alerting, information needed to accurately determine whenand how much power must be brought online to compensate for adecrease/loss of distributed energy resources (DER) and/or distributedgeneration (DG) energy being driven into the grid.
 32. The monitoringsystem of claim 9, wherein the processor is further configured forproviding accurate, time-based measurements of transformer loading thatcan be used in mathematical models to calculate life expectancy basedupon a load profile the transformer experiences.
 33. The monitoringsystem of claim 9, wherein the processor is further configured todetermine what phase a single-phase distribution transformer is coupledto and determining cumulative loads on an associated feeder.
 34. Themonitoring system of claim 33, wherein the processor is furtherconfigured to measure an alternating current (A/C) voltage line cyclezero crossing using clocks set by sub-millisecond time servers, todetermine which devices are connected to which phase.
 35. The monitoringsystem of claim 9, wherein the processor is further configured forplotting voltage profiles for distribution transformers on a feeder andenable a utility engineer to locate distribution transformers that donot have their voltage tap settings adjusted to proper values.
 36. Themonitoring system of claim 9, further comprising weather data collectionsensors and wherein the processor is further configured to transmitweather data collected by the sensors to head-end servers.
 37. Themonitoring system of claim 9, further comprising an audio sensor andwherein the processor is further configured to record sounds from theaudio sensor and transmit sound recordings in an alert if the audiosensor detects a sound that indicates the transformer is not workingproperly, and/or if nearby conditions warrant an alert message be sentto the operator.
 38. The monitoring system of claim 9, furthercomprising a vapor sensor for detecting a presence of oils and theprocessor is further configured to alert personnel if the presence ofoils is detected.
 39. The monitoring system of claim 9, wherein theprocessor is further configured for determining if the transformermonitoring device has been tampered with via a motion detector,detecting that the current sensors have been unlocked and opened,detecting that the unit has been unsealed and/or opened, and detectingthat an external device has been introduced to the conductors to shielda current signature.
 40. The monitoring system of claim 9, furthercomprising a global positioning system (GPS) and wherein the processoris further configured to align positions of a plurality of transformermonitoring devices with a utility's geographic information system (GIS)to ensure proper alignment with an expected location a plurality oftransformers.
 41. The monitoring system of claim 9, wherein theprocessor is further configured for determining an amount of energy usedby streetlights and based on this determination, the processor isfurther configured to detect when a streetlight is out or a light is onduring daylight hours.
 42. The monitoring system of claim 9, wherein theprocessor is further configured for monitoring whether a flow of poweris negative away from the grid or positive into the grid.
 43. Themonitoring system of claim 9, wherein the processor is furtherconfigured for monitoring power imbalance and when there is the powerimbalance alerting personnel.
 44. The monitoring system of claim 9,wherein the processor is further configured for measuring secondaryvoltage at a plurality of transformers throughout a grid in order toaccomplish voltage optimization and conservation voltage reduction byproviding real-time feedback for an advanced voltage optimizationcontrol scheme.
 45. The monitoring system of claim 9, comprising aplurality of transformer monitoring devices coupled to a respectivedistribution transformer on a feeder, wherein the processor is furtherconfigured for providing accurate state estimations by estimatingvoltage magnitude and angle at every bus at a distribution circuit. 46.The monitoring system of claim 9, wherein the processor is furtherconfigured for displaying heat maps of individual transformers, and/oraggregated transformers, and/or display surrounding environmentalconditions locally or in aggregate.